U.S. patent number 10,758,883 [Application Number 16/511,645] was granted by the patent office on 2020-09-01 for fluid catalytic cracking process and apparatus for maximizing light olefin yield and other applications.
This patent grant is currently assigned to LUMMUS TECHNOLOGY LLC. The grantee listed for this patent is Lummus Technology Inc.. Invention is credited to Justin Breckenridge, Liang Chen, Michael Dorsey, Jon A. Hood, Peter Loezos, Rama Rao Marri, Hardik Singh, Bryan Tomsula.
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United States Patent |
10,758,883 |
Chen , et al. |
September 1, 2020 |
Fluid catalytic cracking process and apparatus for maximizing light
olefin yield and other applications
Abstract
Apparatus and processes herein provide for converting
hydrocarbon feeds to light olefins and other hydrocarbons. The
processes and apparatus include, in some embodiments, feeding a
hydrocarbon, a first catalyst and a second catalyst to a reactor,
wherein the first catalyst has a smaller average particle size and
is less dense than the second catalyst. A first portion of the
second catalyst may be recovered as a bottoms product from the
reactor, and a cracked hydrocarbon effluent, a second portion of
the second catalyst, and the first catalyst may be recovered as an
overhead product from the reactor. The second portion of the second
catalyst may be separated from the overhead product, providing a
first stream comprising the first catalyst and the hydrocarbon
effluent and a second stream comprising the separated second
catalyst, allowing return of the separated second catalyst in the
second stream to the reactor.
Inventors: |
Chen; Liang (Houston, TX),
Loezos; Peter (Houston, TX), Marri; Rama Rao (Houston,
TX), Tomsula; Bryan (Houston, TX), Hood; Jon A.
(Houston, TX), Singh; Hardik (Houston, TX), Dorsey;
Michael (Houston, TX), Breckenridge; Justin (Houston,
TX) |
Applicant: |
Name |
City |
State |
Country |
Type |
Lummus Technology Inc. |
Bloomfield |
NJ |
US |
|
|
Assignee: |
LUMMUS TECHNOLOGY LLC
(Bloomfield, NJ)
|
Family
ID: |
69101823 |
Appl.
No.: |
16/511,645 |
Filed: |
July 15, 2019 |
Prior Publication Data
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Document
Identifier |
Publication Date |
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US 20200009523 A1 |
Jan 9, 2020 |
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Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
Issue Date |
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15706348 |
Sep 15, 2017 |
10351786 |
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62395707 |
Sep 16, 2016 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
B01J
8/32 (20130101); C10G 51/06 (20130101); C10G
11/182 (20130101); B01J 8/0055 (20130101); B01J
8/26 (20130101); C10G 51/026 (20130101); C10G
2300/1044 (20130101); C10G 2400/20 (20130101); C10G
2400/30 (20130101); B01J 2208/00805 (20130101); C10G
2300/70 (20130101); B01J 2208/00991 (20130101) |
Current International
Class: |
B01J
8/32 (20060101); C10G 11/18 (20060101); B01J
8/26 (20060101); B01J 8/00 (20060101); C10G
51/02 (20060101); C10G 51/06 (20060101) |
Field of
Search: |
;585/921,922
;208/108,109,111.01,113,118,121,125,126 |
References Cited
[Referenced By]
U.S. Patent Documents
Foreign Patent Documents
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0272973 |
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Jun 1988 |
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EP |
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0489723 |
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Oct 1992 |
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EP |
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2134286 |
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Aug 1999 |
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RU |
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Other References
Office Action issued in corresponding Russian Application No.
2019111142 dated Sep. 17, 2019, and English translation thereof (18
pages). cited by applicant .
Office Action issued in related U.S. Appl. No. 16/511,425, dated
Jan. 2, 2020 (13 pages). cited by applicant .
Harris, John "MILOS--Shell's ultimate flexible FCC technology in
delivering diesel/propylene" RRTC paper on MILOS Sep. 2008 (10
pages). cited by applicant .
Office Action issued in corresponding Russian Application No.
2019111142/04(021643) dated Dec. 24, 2019, and English translation
thereof (14 pages). cited by applicant .
Extended European Search Report issued in corresponding European
Application No. 17851515.1, dated Apr. 17, 2020 (7 pages). cited by
applicant .
Office Action with English translation issued in corresponding
Japanese Application No. 2019536468, dated Apr. 28, 2020 (7 pages).
cited by applicant.
|
Primary Examiner: Dang; Thuan D
Attorney, Agent or Firm: Osha Liang LLP
Claims
What is claimed:
1. A process for the conversion of hydrocarbons, comprising:
feeding a mixture of first particles and second particles from a
regenerator to a transport vessel or riser reactor, wherein the
first particles have a smaller average particle size and/or are
less dense than the second particles, and wherein the first
particles and second particles may independently be catalytic or
non-catalytic particles; feeding a reactive and/or non-reactive
carrier fluid to the transport vessel or riser reactor; recovering
an overhead product from the transport vessel/riser reactor
comprising the carrier fluid and/or a reaction product of the
carrier fluid, the second particles, and the first particles;
feeding the overhead product to an integrated disengagement vessel,
the integrated disengagement vessel comprising: a housing; a solids
separation device disposed within the housing for separating the
second particles from the overhead product to provide a first
stream, comprising the first particles and the carrier fluid and/or
a reaction product of the carrier fluid, and a second stream,
comprising the separated second particles; one or more cyclones
disposed within the housing for separating the first stream to
recover a solids fraction, comprising the first particles, and a
vapor fraction, comprising the carrier fluid and/or a reaction
product of the carrier fluid; an internal vessel disposed within
the housing for receiving the second stream comprising the
separated second particles; an annular region between the housing
and the internal vessel for receiving the solids fraction
comprising the first particles; a vapor outlet for recovering the
vapor fraction; a first solids outlet fluidly connected to the
annular region; and a second solids outlet fluidly connected to the
internal vessel; recovering the solids fraction from the annular
region via the first solids outlet; and recovering the separated
second particles via the second solids outlet.
2. The process of claim 1, further comprising feeding the solids
fraction comprising the separated first particles from the annular
region to the regenerator.
3. The process of claim 2, further comprising feeding the separated
second particles from the internal vessel to the transport vessel
or riser reactor, wherein the separated second particles are mixed
with the mixture of first particles and second particles from the
regenerator.
4. The process of claim 1, further comprising feeding the separated
second particles from the internal vessel to the regenerator.
5. The process of claim 4, further comprising feeding the solids
fraction comprising the separated first particles from the annular
region to the transport vessel or riser reactor, wherein the
separated second particles are mixed with the mixture of first
particles and second particles from the regenerator.
6. The process of claim 1, further comprising: feeding the
separated second particles from the internal vessel to a reactor;
contacting the separated second particles with a hydrocarbon
feedstock to crack the hydrocarbon feedstock.
7. A process for the conversion of hydrocarbons, comprising:
feeding a mixture of first particles and second particles from a
regenerator to a riser reactor, wherein the first particles have a
smaller average particle size and/or are less dense than the second
particles, and wherein the first particles and second particles may
independently be catalytic or non-catalytic particles; feeding a
hydrocarbon fraction to the riser reactor and contacting the
hydrocarbon fraction with the mixture of first particles and second
particles to convert at least a portion of the hydrocarbon
fraction; recovering an overhead product from the riser reactor
comprising the converted hydrocarbon fraction, the second
particles, and the first particles; feeding the overhead product to
an integrated disengagement vessel, the integrated disengagement
vessel comprising: a housing; a solids separation device disposed
within the housing for separating the second particles from the
overhead product to provide a first stream, comprising the first
particles and the converted hydrocarbon fraction, and a second
stream, comprising the separated second particles; one or more
cyclones disposed within the housing for separating the first
stream to recover a solids fraction, comprising the first
particles, and a vapor fraction, comprising the converted
hydrocarbon fraction; an internal vessel disposed within the
housing for receiving the second stream comprising the separated
second particles; an annular region between the housing and the
internal vessel for receiving the solids fraction comprising the
first particles; a vapor outlet for recovering the vapor fraction;
feeding the solids fraction from the annular region to the
regenerator; and enhancing a concentration of the second particles
within the riser reactor by feeding the separated second particles
from the internal vessel to the riser reactor, wherein the
separated second particles are mixed with the mixture of first
particles and second particles from the regenerator to form a
converted hydrocarbon fraction.
8. The process of claim 7, further comprising: feeding a second
hydrocarbon feedstock and a mixture of first particles and second
particles to a second reactor; contacting the mixture of first and
second particles with a second hydrocarbon feedstock to crack the
second hydrocarbon feedstock and form a second reactor effluent
comprising lighter hydrocarbons and a mixture of first and second
particles; feeding the second reactor effluent to a separator to
separate the first and second particles from the lighter
hydrocarbons and the converted hydrocarbon effluent; and recovering
a hydrocarbon product from the separator.
9. The process of claim 8, further comprising: feeding fresh second
particles to the riser reactor; and feeding fresh first particles
to the regenerator.
10. The process of claim 8, further comprising: feeding the vapor
fraction recovered via the vapor outlet and feeding the hydrocarbon
product recovered from the separator to a fractionation system for
separating the hydrocarbon products therein into two or more
hydrocarbon fractions including a naphtha fraction; and feeding the
naphtha fraction to the riser reactor as the hydrocarbon
feedstock.
11. The process of claim 7, further comprising adjusting a vapor
split ratio in the solids separation device to carry over a portion
of the second catalyst in the first stream.
Description
FIELD OF THE DISCLOSURE
Embodiments herein generally relate to systems and processes for
enhancing the productivity and/or flexibility of mixed catalyst
systems. Some embodiments disclosed herein relate to a fluid
catalytic cracking apparatus and process for maximizing the
conversion of a heavy hydrocarbon feed, such as vacuum gas oil
and/or heavy oil residues into very high yield of light olefins,
such as propylene and ethylene, aromatics and gasoline with high
octane number.
BACKGROUND
In recent times, production of light olefins via fluid catalytic
cracking (FCC) processes has been considered one of the most
attractive propositions. Additionally, there is an ever increasing
demand for petrochemical building blocks such as propylene,
ethylene, and aromatics (benzene, toluene, xylenes, etc.). Further,
integration of petroleum refineries with a petrochemicals complex
has become a preferred option for both economic and environmental
reasons.
Global trends also show that there is increased demand for middle
distillates (diesel) than that of gasoline product. In order to
maximize middle distillates from FCC process, it is required to
operate FCC at lower reactor temperature and a different catalyst
formulation. The downside of such change is decreased light olefins
yield because of FCC unit operating at much lower reactor
temperature. This will also reduce feedstock for Alkylation
units.
Several fluidized bed catalytic processes have been developed over
the last two decades, adapting to the changing market demands. For
example, U.S. Pat. No. 7,479,218 discloses a fluidized catalytic
reactor system in which a riser-reactor is divided into two
sections of different radii in order to improve the selectivity for
light olefins production. The first part of the riser reactor with
lesser radii is employed for cracking heavy feed molecules to
naphtha range. The enlarged radii portion, the second part of the
riser reactor is used for further cracking of naphtha range
products into light olefins such as propylene, ethylene, etc.
Though the reactor system concept is fairly simple, the degree of
selectivity to light olefins is limited for the following reasons:
(1) the naphtha range feed streams contact partially coked or
deactivated catalyst; (2) the temperature in the second part of the
reaction section is much lower than the first zone because of the
endothermic nature of the reaction in both sections; and (3) lack
of the high activation energy required for light feed cracking as
compared to that of heavy hydrocarbons.
U.S. Pat. Nos. 6,106,697, 7,128,827, and 7,323,099 employ two stage
fluid catalytic cracking (FCC) units to allow a high degree of
control for selective cracking of heavy hydrocarbons and naphtha
range feed streams. In the 1.sup.st stage FCC unit, consisting of a
riser reactor, stripper and regenerator for converting gas
oil/heavy hydrocarbon feeds into naphtha boiling range products, in
the presence of Y-type large pore zeolite catalyst. A 2.sup.nd
stage FCC unit with a similar set of vessels/configuration is used
for catalytic cracking of recycled naphtha streams from the
1.sup.st stage. Of course, the 2.sup.nd stage FCC unit employs a
ZSM-5 type (small pore zeolite) catalyst to improve the selectivity
to light olefins. Though this scheme provides a high degree of
control over the feed, catalyst and operating window selection and
optimization in a broad sense, the 2.sup.nd stage processing of
naphtha feed produces very little coke that is insufficient to
maintain the heat balance. This demands heat from external sources
to have adequate temperature in the regenerator for achieving good
combustion and to supply heat for feed vaporization and endothermic
reaction. Usually, torch oil is burned in the 2.sup.nd stage FCC
regenerator, which leads to excessive catalyst deactivation due to
higher catalyst particle temperatures and hot spots.
U.S. Pat. No. 7,658,837 discloses a process and device to optimize
the yields of FCC products by utilizing a part of a conventional
stripper bed as a reactive stripper. Such reactive stripping
concept of second reactor compromises the stripping efficiency to
some extent and hence may lead to increased coke load to
regenerator. The product yield and selectivity is also likely to be
affected due to contact of the feed with coked or deactivated
catalyst. Further, reactive stripper temperatures cannot be changed
independently because the riser top temperature is directly
controlled to maintain a desired set of conditions in the
riser.
US2007/0205139 discloses a process to inject hydrocarbon feed
through a first distributor located at the bottom section of the
riser for maximizing gasoline yield. When the objective is to
maximize light olefins, the feed is injected at the upper section
of the riser through a similar feed distribution system with an
intention to decrease the residence time of hydrocarbon vapors in
the riser.
WO2010/067379 aims at increasing propylene and ethylene yields by
injecting C.sub.4 and olefinic naphtha streams in the lift zone of
the riser below the heavy hydrocarbon feed injection zone. These
streams not only improve the light olefins yield but also act as
media for catalyst transport in place of steam. This concept helps
in reducing the degree of thermal deactivation of the catalyst.
However, this lacks in flexibility of varying operating conditions
such as temperature and WHSV in the lift zone, which are critical
for cracking of such light feed steams. This is likely to result in
inferior selectivity to the desired light olefins.
U.S. Pat. No. 6,869,521 discloses that contacting a feed derived
from FCC product (particularly naphtha) with a catalyst in a second
reactor operating in fast fluidization regime is useful for
promoting hydrogen transfer reactions and also for controlling
catalytic cracking reactions.
U.S. Pat. No. 7,611,622 discloses an FCC process employing dual
risers for converting a C.sub.3/C.sub.4 containing feedstock to
aromatics. The first and second hydrocarbon feeds are supplied to
the respective 1.sup.st and 2.sup.nd risers in the presence of
gallium enriched catalyst and the 2.sup.nd riser operates at higher
reaction temperature than the first.
U.S. Pat. No. 5,944,982 discloses a catalytic process with dual
risers for producing low sulfur and high octane gasoline. The
second riser is used to process recycle the heavy naphtha and light
cycle oils after hydro-treatment to maximize the gasoline yield and
octane number.
US20060231461 discloses a process that maximizes production of
light cycle oil (LCO) or middle distillate product and light
olefins. This process employs a two reactor system where the first
reactor (riser) is used for cracking gas oil feed into
predominantly LCO and a second concurrent dense bed reactor is used
for cracking of naphtha recycled from the first reactor. This
process is limited by catalyst selectivity and lacks in the desired
level of olefins in naphtha due to operation of the first reactor
at substantially lower reaction temperatures.
U.S. Pat. No. 6,149,875 deals with removal of feed contaminants
such as concarbon and metals with adsorbent. The FCC catalyst is
separated from adsorbent using the differences between
transport/terminal velocity of the FCC catalyst and adsorbent.
U.S. Pat. No. 7,381,322 disclosed an apparatus and process to
separate catalyst from a metal adsorbent in stripper cum separator,
before a regeneration step for eliminating the adverse effects of
contaminant metals deposited on the adsorbent. This patent employs
the difference in minimum/bubbling velocity differences and the
application is mainly to segregate FCC catalyst from adsorbent.
SUMMARY
It has been found that it is possible to use a two-reactor scheme
to crack hydrocarbons, including cracking of a C.sub.4, lighter
C.sub.5 fraction, naphtha fraction, methanol, etc. for the
production of light olefins, where the two-reactor scheme does not
have limitations on selectivity and operability, meets heat balance
requirements, and also maintains a low piece count. Select
embodiments disclosed herein use a conventional riser reactor in
combination with a mixed flow (e.g., including both counter-current
and co-current catalyst flows) fluidized bed reactor designed for
maximizing light olefins production. The effluents from the riser
reactor and mixed flow reactor are processed in a common catalyst
disengagement vessel, and the catalysts used in each of the riser
reactor and the mixed flow reactor may be regenerated in a common
catalyst regeneration vessel. This flow scheme is effective for
maintaining a high cracking activity, overcomes the heat balance
problems, and also improves yield and selectivity of light olefins
from various hydrocarbon streams, yet simplifies the product
quenching and unit hardware, as will be described in more detail
below.
In one aspect, embodiments disclosed herein relate to a process for
the conversion or catalytic cracking of hydrocarbons. The process
may include feeding a hydrocarbon, a first particle and a second
particle to a reactor, where the first particle has a smaller
average particle size and/or is less dense than the second
particle, and where the first and second particles may be catalytic
or non-catalytic. A first portion of the second particle may be
recovered as a bottoms product from the reactor; and a cracked
hydrocarbon effluent, a second portion of the second particle, and
the first particle may be recovered as an overhead product from the
reactor. The second portion of the second particle may be separated
from the overhead product to provide a first stream comprising the
first particle and the hydrocarbon effluent and a second stream
comprising the separated second particle, allowing return of the
separated second particle in the second stream to the reactor.
In another aspect, embodiments disclosed herein relate to a system
for the catalytic cracking of hydrocarbons. The system may include
a first reactor for contacting a first and a second cracking
catalyst with a hydrocarbon feedstock to convert at least a portion
of the hydrocarbon feedstock to lighter hydrocarbons. An overhead
product line provides for recovering from the first reactor a first
stream comprising first cracking catalyst, a first portion of the
second cracking catalyst, and hydrocarbons. A bottoms product line
provides for recovering from the first reactor a second stream
comprising a second portion of the second cracking catalyst. A
separator may be used for separating second cracking catalyst from
the first stream, producing a hydrocarbon effluent comprising
hydrocarbons and the first cracking catalyst. A feed line is
provided for returning separated second cracking catalyst from the
separator to the first reactor.
The system for catalytic cracking of hydrocarbons may also include
a riser reactor for contacting a mixture of the first cracking
catalyst and the second cracking catalyst with a second hydrocarbon
feedstock to convert at least a portion of the second hydrocarbon
feedstock to lighter hydrocarbons and recover a riser reactor
effluent comprising the lighter hydrocarbons and the mixture of the
first cracking catalyst and the second cracking catalyst. A second
separator may be provided for separating the second cracking
catalyst from the hydrocarbon effluent and for separating the
mixture of first and second cracking catalysts from the riser
reactor effluent. A catalyst regenerator for regenerating first and
second cracking catalyst recovered in the second separator and the
second portion of the first cracking catalyst recovered in the
bottoms product line may also be used.
In another aspect, embodiments disclosed herein relate to a process
for the conversion of hydrocarbons. The process may include:
feeding a first catalyst to a reactor; feeding a second catalyst to
the reactor, wherein the first catalyst has a smaller average
particle size and/or is less dense than the first catalyst, and
feeding a hydrocarbon feedstock to the reactor. An overhead
effluent may be recovered from the reactor, the effluent including
cracked hydrocarbon, the first catalyst, and the second catalyst.
The second catalyst may be separated from the overhead product to
provide a first stream comprising the first catalyst and the
hydrocarbon effluent and a second stream comprising the separated
second catalyst, allowing return of the separated second catalyst
in the second stream to the reactor.
In another aspect, embodiments herein are directed toward a
separator for separating catalysts or other particles based on size
and/or density difference. The separator may have a minimum of one
inlet and may also have a minimum of two outlets for separating
particles from carrier gases. The carrier gas enters the separator
with the particles whereupon inertial, centrifugal and/or
gravitational forces may be exerted on the particles such that a
portion of the particles and carrier gas are collected in the first
outlet and a portion of the particles along with the carrier gas
are collected in the second outlet. The combination of forces in
the separator may have the effect of enriching an outlet stream in
particle size and/or density versus the inlet concentration. The
separator may have additional carrier gas distribution or
fluidization inside of the vessel/chamber to exert additional
forces on the particles which may facilitate enhanced
classification.
In another aspect, embodiments herein are directed toward an
inertial separator for separating catalysts or other particles
based on size and/or density. The inertial separator may include an
inlet for receiving a mixture comprising a carrier gas, a first
particle type, and a second particle type. Each particle type may
have an average particle size and a particle size distribution,
which may be different or overlapping, and an average density. The
second particle type may have an average particle size and/or
average density greater than the first particle type. The inertial
separator may include a U-shaped conduit including a first vertical
leg, a base of the U-shape, and a second vertical leg. The U-shaped
conduit may fluidly connect the inlet via the first vertical leg to
a first outlet and a second outlet, the first outlet being
connected proximate the base of the U-shaped conduit and the second
outlet being connected to the second vertical leg. The U-shaped
inertial separator may be configured to: separate at least a
portion of the second particle type from the carrier gas and the
first particle type, recover the second particle type via the first
outlet, and recover the carrier gas and the first particle type via
the second outlet. The separator may also include a distributor
disposed within or proximate the second outlet for introducing a
fluidizing gas, facilitating additional separation of the first
particle type from the second particle type. The separator, in some
embodiments, may be configured such that a cross-sectional area of
the U-shaped conduit or a portion thereof is adjustable. For
example, in some embodiments the separator may include a movable
baffle disposed within one or more sections of the U-shaped
conduit.
In another aspect, embodiments herein are directed toward an
inertial separator for separating catalysts or other particles
based on size and/or density as above. The inertial separator may
include an inlet horizontal conduit which traverses a chamber
before being deflected by a baffle. The chamber is connected to a
first vertical outlet and a first horizontal outlet. The baffle may
be located in the middle, proximate the inlet, or proximate the
outlet of the chamber. The baffle may be at an angle or moveable
such that to deflect more or less catalyst particles. The baffle
chamber separator may be configured to: separate at least a portion
of the second particle type from the carrier gas and the first
particle type, recover the second particle type via the first
vertical outlet and recover the carrier gas and the first particle
type via the first horizontal outlet. The separator may also
include a distributor disposed within or proximate the first
vertical outlet for introducing a fluidizing gas, facilitating
additional separation of the first particle type from the second
particle type.
In another aspect, embodiments herein are directed toward an
inertial separator for separating catalysts or other particles
based on size and/or density as above. The inertial separator may
include a vertical inlet connected to a chamber where one or more
vertical sides of the chamber are equipped with narrow slot
outlets, which may be described as louvers. The number of louvers
may vary depending on the application and the angle of the louver
may be adjustable in order to control the amount of vapor leaving
the louver outlets. The chamber is also connected to a first
vertical outlet at the bottom of the chamber. The louver separator
may be configured to: separate at least a portion of the second
particle type from the carrier gas and the first particle type,
recover the second particle type via the first vertical outlet and
recover the carrier gas and the first particle type via the louver
outlets. The separator may also include a distributor disposed
within or proximate the first vertical outlet for introducing for
introducing a fluidizing gas, facilitating additional separation of
the first particle type from the second particle type.
The above described separators may also be used in association with
reactors, regenerators, and catalyst feed systems to enhance system
performance and flexibility.
In one aspect, embodiments disclosed herein relate to a process for
the conversion of hydrocarbons. The process may include
regenerating a catalyst mixture comprising a first catalyst and a
second particle in a regenerator, wherein the first catalyst has a
smaller average particle size and/or is less dense than the second
particle, and wherein the second particle may be catalytic or
non-catalytic. The catalyst mixture and hydrocarbons may be fed to
a riser reactor to convert at least a portion of the hydrocarbons
and recover a first effluent comprising the catalyst mixture and
converted hydrocarbons. The catalyst mixture may also be fed to a
second reactor. Feeding a hydrocarbon feedstock to the second
reactor and fluidizing the catalyst mixture may contact the
hydrocarbon feedstock with the catalyst mixture to convert the
hydrocarbons and provide for recovering an overhead product from
the second reactor comprising the second particle, the first
catalyst, and a reacted hydrocarbon product. The second particle
may then be separated from the overhead product to provide a first
stream comprising the first catalyst and the reacted hydrocarbon
product and a second stream comprising the separated second
particle, returning the separated second particle in the second
stream to the reactor.
In another aspect, embodiments disclosed herein relate to a process
for the conversion of hydrocarbons. The process may include
withdrawing a mixture comprising a first catalyst and a second
catalyst from a catalyst regenerator and feeding the mixture and
hydrocarbons to a riser reactor to convert at least a portion of
the hydrocarbons and recover a first effluent comprising the
catalyst mixture and converted hydrocarbons, wherein the first
catalyst has a smaller average particle size and/or is less dense
than the second catalyst. The process may also include withdrawing
the mixture comprising a first catalyst and a second catalyst from
the catalyst regenerator and feeding the mixture to a catalyst
separation system, fluidizing the mixture comprising the first
catalyst and the second catalyst with a fluidization medium, and
separating the first catalyst from the second catalyst in the
catalyst separation system to recover a first stream comprising the
first catalyst and the fluidization medium and a second stream
comprising the second catalyst. A hydrocarbon feedstock and either
the first stream or the second stream may then be fed to a reactor
to react at least a portion of the hydrocarbon to produce a
converted hydrocarbon.
In another aspect, embodiments disclosed herein relate to a process
for the conversion of hydrocarbons. The process may include feeding
a hydrocarbon feedstock and a catalyst mixture comprising a first
catalyst and a second catalyst to a riser reactor, wherein the
first catalyst has a smaller average particle size and/or is less
dense than the second catalyst. An effluent from the riser reactor
may then be separated to recover a first stream comprising the
first catalyst and converted hydrocarbon feedstock and a second
stream comprising the second catalyst, and the second stream may be
fed to the riser reactor.
In another aspect, embodiments disclosed herein relate to a process
for the conversion of hydrocarbons. The process may include
withdrawing a mixture comprising a first catalyst and a second
catalyst from a catalyst regenerator and feeding the mixture to a
catalyst feed/separation system, wherein the first catalyst has a
smaller average particle size and/or is less dense than the second
catalyst. The first catalyst may be separated from the second
catalyst in the catalyst feed/separation system to produce a first
stream comprising the first catalyst and a second stream comprising
the second catalyst. A hydrocarbon feedstock and either the first
stream or the second stream may then be fed to a riser reactor to
react at least a portion of the hydrocarbon to produce a converted
hydrocarbon.
In another aspect, embodiments disclosed herein relate to a system
for the conversion of hydrocarbons. The system may include a
catalyst regenerator, and a first catalyst feed line for
withdrawing a mixture comprising a first catalyst and a second
catalyst from the catalyst regenerator and feeding the mixture to a
riser reactor, wherein the first catalyst has a smaller average
particle size and/or is less dense than the second catalyst. The
system may also include a second catalyst feed line for withdrawing
the mixture comprising a first catalyst and a second catalyst from
the catalyst regenerator and feeding the mixture to a catalyst
separation system, and a fluidization medium feed line for
fluidizing the mixture withdrawn via the second catalyst feed line
with a fluidization medium and separating the first catalyst from
the second catalyst in the catalyst separation system to recover a
first stream comprising the first catalyst and the fluidization
medium and a second stream comprising the second catalyst. A
reactor may be provided for contacting a hydrocarbon feedstock and
either the first stream or the second stream to react at least a
portion of the hydrocarbon to produce a converted hydrocarbon.
In another aspect, embodiments disclosed herein relate to a system
for the conversion of hydrocarbons. The system may include a riser
reactor for contacting a hydrocarbon feedstock with a catalyst
mixture comprising a first catalyst and a second catalyst, wherein
the first catalyst has a smaller average particle size and/or is
less dense than the second catalyst. A catalyst separation system
is provided for separating a riser reactor effluent to recover a
first stream comprising the first catalyst and converted
hydrocarbon feedstock and a second stream comprising the second
catalyst. A flow line feeds the second stream to the riser
reactor.
In another aspect, embodiments disclosed herein relate to a system
for the conversion of hydrocarbons. The system may include a
catalyst withdrawal line for withdrawing a mixture comprising a
first catalyst and a second catalyst from a catalyst regenerator
and feeding the mixture to a catalyst feed/separation system,
wherein the first catalyst has a smaller average particle size
and/or is less dense than the second catalyst. The catalyst
feed/separation system separates the first catalyst from the second
catalyst in the catalyst feed/separation system to produce a first
stream comprising the first catalyst and a second stream comprising
the second catalyst. A riser reactor contacts a hydrocarbon
feedstock and either the first stream or the second stream to react
at least a portion of the hydrocarbon to produce a converted
hydrocarbon.
The apparatus and processes disclosed herein use significantly
different technique than disclosed in the above patents (such as
U.S. Pat. Nos. 6,149,875 and 7,381,322) to separate particulate
mixtures. The purpose of the present disclosure is also different;
the prior art disclosures focus on removing the contaminants from
the catalyst by introducing an adsorbent. However, the present
invention aims at improving the conversion, selectivity and heat
balance by concentrating a selected catalyst in a reactor, such as
concentrating the ZSM-5/11 in the second reactor.
A process for the conversion of hydrocarbons. The process may
include feeding a mixture of first particles and second particles
from a regenerator to a transport vessel or riser reactor. The
first particles may have a smaller average particle size and/or are
less dense than the second particles, and the first particles and
second particles may independently be catalytic or non-catalytic
particles. The process may also include feeding a reactive and/or
non-reactive carrier fluid to the transport vessel or riser
reactor, and recovering an overhead product from the transport
vessel/riser reactor comprising the carrier fluid and/or a reaction
product of the carrier fluid, the second particles, and the first
particles.
The overhead product may be fed to an integrated disengagement
vessel. The integrated disengagement vessel may include a housing.
A solids separation device may be disposed within the housing for
separating the second particles from the overhead product to
provide a first stream, comprising the first particles and the
carrier fluid and/or a reaction product of the carrier fluid, and a
second stream, comprising the separated second particles. One or
more cyclones may also be disposed within the housing, the cyclones
provided for separating the first stream to recover a solids
fraction, comprising the first particles, and a vapor fraction,
comprising the carrier fluid and/or a reaction product of the
carrier fluid. Further, an internal vessel may be disposed within
the housing for receiving the second stream comprising the
separated second particles. An annular region may be formed between
the housing and the internal vessel for receiving the solids
fraction comprising the first particles. The disengagement vessel
may also include a vapor outlet, for recovering the vapor fraction,
a first solids outlet, for recovering the solids fraction from the
annular region, and a second solids outlet, for recovering the
separated second particles from the internal vessel.
The process may also include recovering the solids fraction from
the annular region via the first solids outlet. Further, the
separated second particles may be recovered via the second solids
outlet.
In some embodiments, the solids fraction comprising the separated
first particles may be fed from the annular region to the
regenerator. The separated second particles from the internal
vessel may be fed to the transport vessel or riser reactor, wherein
the separated second particles are mixed with the mixture of first
particles and second particles from the regenerator.
In some embodiments, the separated second particles may be fed from
the internal vessel to the regenerator. The solids fraction
comprising the separated first particles may be fed from the
annular region to the transport vessel or riser reactor, wherein
the separated second particles are mixed with the mixture of first
particles and second particles from the regenerator.
In yet other embodiments, the separated second particles may be fed
from the internal vessel to an additional reactor. The separated
second particles may be contacted in the additional reactor with a
hydrocarbon feedstock to crack the hydrocarbon feedstock.
In another aspect, embodiments disclosed herein relate to a process
for the conversion of hydrocarbons. The process may include feeding
a mixture of first particles and second particles from a
regenerator to a riser reactor, wherein the first particles have a
smaller average particle size and/or are less dense than the second
particles, and wherein the first particles and second particles may
independently be catalytic or non-catalytic particles. A
hydrocarbon fraction may be fed to the riser reactor, the process
including contacting the hydrocarbon fraction with the mixture of
first particles and second particles to convert at least a portion
of the hydrocarbon fraction. An overhead product may be recovered
from the riser reactor comprising the converted hydrocarbon
fraction, the second particles, and the first particles. The
overhead product may then be fed to an integrated disengagement
vessel, the integrated disengagement vessel comprising: a housing;
a solids separation device disposed within the housing for
separating the second particles from the overhead product to
provide a first stream, comprising the first particles and the
carrier fluid and/or a reaction product of the carrier fluid, and a
second stream, comprising the separated second particles; one or
more cyclones disposed within the housing for separating the first
stream to recover a solids fraction, comprising the first
particles, and a vapor fraction, comprising the carrier fluid
and/or a reaction product of the carrier fluid; an internal vessel
disposed within the housing for receiving the second stream
comprising the separated second particles; an annular region
between the housing and the internal vessel for receiving the
solids fraction comprising the first particles; and, a vapor outlet
for recovering the vapor fraction. The solids fraction may be fed
from the annular region to the regenerator. Further, the process
may include enhancing a concentration of the second particles
within the riser reactor by feeding the separated second particles
from the internal vessel to the riser reactor, wherein the
separated second particles are mixed with the mixture of first
particles and second particles from the regenerator.
The process may further include feeding a second hydrocarbon
feedstock and a mixture of first particles and second particles to
a second reactor. In the second reactor, the mixture of first and
second particles may be contacted with a second hydrocarbon
feedstock to crack the second hydrocarbon feedstock and form a
second reactor effluent comprising lighter hydrocarbons and a
mixture of first and second particles. The second reactor effluent
may be fed to a separator to separate the first and second
particles from the lighter hydrocarbons and the converted
hydrocarbon effluent, and a hydrocarbon product may be recovered
from the separator.
The process, in other embodiments, may further include feeding the
vapor fraction recovered via the vapor outlet and feeding the
hydrocarbon product recovered from the separator to a fractionation
system for separating the hydrocarbon products therein into two or
more hydrocarbon fractions including a naphtha fraction. The
naphtha fraction may be fed to the riser reactor as the hydrocarbon
feedstock.
In other embodiments, the process may include adjusting a vapor
split ratio in the solids separation device to carry over a portion
of the second catalyst in the first stream.
In another aspect, embodiments herein relate to a system for
cracking hydrocarbons. The system may include a regenerator, a
riser reactor, an integrated disengagement vessel. The riser
reactor may be configured to receive a mixture of first particles
and second particles from the regenerator, wherein the first
particles have a smaller average particle size and/or are less
dense than the second particles, and wherein the first particles
and second particles may independently be catalytic or
non-catalytic particles. The riser reactor may also be configured
to contact a hydrocarbon fraction with the mixture of first
particles and second particles, to convert at least a portion of
the hydrocarbon fraction and produce an overhead product from the
riser reactor comprising the converted hydrocarbon fraction, the
second particles, and the first particles.
The integrated disengagement vessel configured to receive the
overhead product, the integrated disengagement vessel may include a
housing. A solids separation device may be disposed within the
housing, and may be configured for separating the second particles
from the overhead product to provide a first stream, comprising the
first particles and the carrier fluid and/or a reaction product of
the carrier fluid, and to provide a second stream, comprising the
separated second particles. One or more cyclones may also be
disposed within the housing, the cyclones provided for separating
the first stream to provide a solids fraction, comprising the first
particles, and a vapor fraction, comprising the carrier fluid
and/or a reaction product of the carrier fluid. An internal vessel
may also be disposed within the housing, the internal vessel
configured for receiving the second stream comprising the separated
second particles. An annular region may be formed between the
housing and the internal vessel, the annular region configured for
receiving the solids fraction comprising the first particles. The
integrated disengagement vessel may also include: a vapor outlet
for recovering the vapor fraction; a flow line for feeding the
solids fraction from the annular region to the regenerator; and a
flow line for enhancing a concentration of the second particles
within the riser reactor by feeding the separated second particles
from the internal vessel to the riser reactor, wherein the
separated second particles are mixed with the mixture of first
particles and second particles from the regenerator. In some
embodiments, the system may also include a controller configured to
adjust a vapor split ratio in the solids separation device to carry
over a portion of the second catalyst in the first stream.
In summary, most of the state of the art included dual
riser/reactor configurations or two stage fluid catalytic cracking
process schemes/apparatus. The second/parallel reactor used for
processing light feed (naphtha or/and C4 streams) are either
concurrent pneumatic flow riser type or dense bed reactors. It is
well known in the art that ZSM-5 is preferable catalyst/additive to
convert naphtha/C4 streams into propylene and ethylene. However, in
processes employing two reactors, the second reactor also receives
Y-zeolite catalyst with small fractions of ZSM-5 additive. In other
process schemes, FCC type reactor-regenerator concepts are employed
for maximizing light olefins from naphtha/C4 streams. Such schemes
pose heat balance problems due to insufficient coke production. The
processes and systems disclosed herein considers separating
catalysts, such as ZSM-5 or ZSM-11 additive from Y-zeolite &
ZSM-5/ZSM-11, in a mixture, so as to have optimal concentration of
ZSM-5 or 11 in the second reactor processing light feed. In
addition, integration of said additional/second reactor with a
conventional FCC unit essentially helps overcoming these drawbacks
(product selectivity and heat balance in particular) of the prior
part and substantially increases the overall conversion and light
olefins yield and increases the capability to process heavier
feedstocks.
Other aspects and advantages will be apparent from the following
description and the appended claims.
BRIEF DESCRIPTION OF DRAWINGS
FIG. 1 is a simplified process flow diagram of a system for
cracking hydrocarbons and producing light olefins according to one
or more embodiments disclosed herein.
FIGS. 2-5 are simplified process flow diagrams of separators useful
in systems according to one or more embodiments disclosed
herein.
FIG. 6 is a simplified process flow diagram of a system for
cracking hydrocarbons and producing light olefins according to one
or more embodiments disclosed herein.
FIG. 7 is a simplified process flow diagram of a system for
cracking hydrocarbons and producing light olefins according to one
or more embodiments disclosed herein.
FIG. 8A is a simplified process flow diagram of a system for
cracking hydrocarbons and producing light olefins according to one
or more embodiments disclosed herein.
FIG. 8B is a simplified process flow diagram of a system for
cracking hydrocarbons and producing light olefins according to one
or more embodiments disclosed herein.
FIG. 8C is a simplified process flow diagram of a system for
cracking hydrocarbons and producing light olefins according to one
or more embodiments disclosed herein.
FIG. 9A is a simplified process flow diagram of a system for
cracking hydrocarbons and producing light olefins according to one
or more embodiments disclosed herein.
FIG. 9B is a simplified process flow diagram of a system for
cracking hydrocarbons and producing light olefins according to one
or more embodiments disclosed herein.
FIG. 10 is a simplified process flow diagram of a system for
cracking hydrocarbons and producing light olefins according to one
or more embodiments disclosed herein.
FIG. 11 is a simplified process flow diagram of a system for
cracking hydrocarbons and producing light olefins according to one
or more embodiments disclosed herein.
FIG. 12 is a simplified process flow diagram of a system for
cracking hydrocarbons and producing light olefins according to one
or more embodiments disclosed herein.
DETAILED DESCRIPTION
As used herein, the terms "catalyst" and "particle" and like terms
may be used interchangeably. Summarized above, and as further
described below, embodiments herein separate mixed particulate
materials based on size and/or density to achieve an advantageous
effect in a reactor system. The particles or particulate materials
used to facilitate catalytic or thermal reaction may include
catalysts, absorbents, and/or heat transfer materials having no
catalytic activity, for example.
In one aspect, embodiments herein relate to a fluid catalytic
cracking apparatus and process for maximizing the conversion of a
heavy hydrocarbon feed, such as vacuum gas oil and/or heavy oil
residues into very high yield of light olefins, such as propylene
and ethylene, aromatics and gasoline with high octane number or
middle distillates, while concurrently minimizing the yield of
heavier bottom product. To accomplish this goal, a secondary
reactor, which may be a mixed flow reactor (including both
co-current and counter-current flow of particles with respect to
vapor flow) or a catalyst-concentrating reactor, can be integrated
with a conventional fluid catalytic cracking reactor, such as a
riser reactor. A heavy hydrocarbon feed is catalytically cracked to
naphtha, middle distillates and light olefins in the riser reactor,
which is a pneumatic flow co-current type reactor. To enhance the
yields and selectivity to light olefins (ethylene and propylene),
cracked hydrocarbon products from the riser reactor, such as
C.sub.4 and naphtha range hydrocarbons (olefins and paraffins), may
be recycled and processed in the secondary reactor (the mixed flow
reactor or the catalyst-concentrating reactor). Alternatively, or
additionally, external feed streams, such as C.sub.4, naphtha, or
other hydrocarbon fractions from other processes such as a steam
cracker, metathesis reactor, or delayed coking unit, and naphtha
range streams, such as straight run naphtha or from delayed coking,
visbreaking or natural gas condensates, among other hydrocarbon
feedstocks, may be processed in the secondary reactor to produce
light olefins, such as ethylene and propylene. The integration of
the secondary reactor with a conventional FCC riser reactor
according to embodiments disclosed herein may overcome the
drawbacks of prior processes, may substantially increase the
overall conversion and light olefins yield, and/or may increases
the capability to process heavier feedstocks.
Integration of the secondary reactor with a conventional FCC riser
reactor according to embodiments disclosed herein may be
facilitated by (a) using a common catalyst regeneration vessel, (b)
using two types of catalyst, one being selective for cracking
heavier hydrocarbons and the other being selective for the cracking
of C.sub.4 and naphtha range hydrocarbons for the production of
light olefins, and (c) using a mixed flow reactor or a
catalyst-concentrating reactor in a flow regime that will partially
separate the two types of catalysts, favoring the contact of the
C.sub.4s or naphtha feed with the catalyst selective for cracking
the same and producing light olefins.
To enhance the operation window of the secondary reactor, and to
provide greater process flexibility, the secondary reactor may be
operated in a flow regime to entrain the catalyst selective for
cracking heavier hydrocarbons, and to entrain at least a portion of
the catalyst selective for the cracking of C.sub.4 and naphtha
range hydrocarbons. The cracked hydrocarbon products and the
entrained catalysts are then fed to a separator to separate the
catalyst selective for the cracking of C.sub.4 and naphtha range
hydrocarbons from the cracked hydrocarbon products and the catalyst
selective for cracking heavier hydrocarbons. This solids separation
vessel is an external vessel to the reactor and is operated at
hydrodynamic properties that enhance the separation of the two
types of catalyst based on their physical properties, such as
particle size and/or density. The separated catalyst, selective for
the cracking of C.sub.4 and naphtha range hydrocarbons, may then be
returned to the reactor for continued reaction and providing an
enhanced concentration of the catalyst selective for the cracking
of C.sub.4 and naphtha range hydrocarbons within the reactor,
improving selectivity of the overall process while also improving
the overall process flexibility due to the enhanced operating
window.
As noted above, the cracking system may utilize two types of
catalysts, each favoring a different type of hydrocarbon feed. The
first cracking catalyst may be a Y-type zeolite catalyst, an FCC
catalyst, or other similar catalysts useful for cracking heavier
hydrocarbon feedstocks. The second cracking catalyst may be a ZSM-5
or ZSM-11 type catalyst or similar catalyst useful for cracking
C.sub.4s or naphtha range hydrocarbons and selective for producing
light olefins. To facilitate the two-reactor scheme disclosed
herein, the first cracking catalyst may have a first average
particle size and density, and may be smaller and/or lighter than
those for the second cracking catalyst, such that the catalysts may
be separated based on density and/or size (e.g., based on terminal
velocity or other characteristics of the catalyst particles).
In the catalyst regeneration vessel, spent catalyst recovered from
both the riser reactor and the secondary reactor is regenerated.
Following regeneration, a first portion of the mixed catalyst may
be fed from the regeneration vessel to a riser reactor (co-current
flow reactor). A second portion of the mixed catalyst may be fed
from the regeneration vessel to the secondary reactor.
In the co-current flow reactor, a first hydrocarbon feed is
contacted with a first portion of the regenerated catalyst to crack
at least a portion of the hydrocarbons to form lighter
hydrocarbons. An effluent may then be recovered from the co-current
flow reactor, the effluent comprising a first cracked hydrocarbon
product and a spent mixed catalyst fraction.
In some embodiments, the secondary reactor is operated in a
fluidization regime sufficient to entrain the first cracking
catalyst, and the second cracking catalyst with the hydrocarbon
products recovered as an effluent from the secondary reactor
overhead outlet. The effluent is then fed to a separator to
separate the cracked hydrocarbon products and the first cracking
catalyst from the second cracking catalyst.
The vapor/first cracking catalyst stream recovered from the
separator may then be forwarded for separation. The second cracking
catalyst recovered from the separator may be recycled back to the
secondary reactor for continued reaction, as noted above.
The first effluent (cracked hydrocarbons and spent mixed catalyst
from the riser reactor) and the second effluent (cracked
hydrocarbons and separated first cracking catalyst from the
secondary reactor) may both be fed to a disengagement vessel to
separate the spent mixed catalyst fraction and the separated first
cracking catalyst from the first and second cracked hydrocarbon
products. The cracked hydrocarbon products, including light
olefins, C.sub.4 hydrocarbons, naphtha range hydrocarbons, and
heavier hydrocarbons may then be separated to recover the desired
products or product fractions.
Thus, processes disclosed herein integrate a secondary mixed-flow
or catalyst-concentrating reactor, external solids separator, and a
riser reactor, with common product separations and catalyst
regeneration, where the catalysts used in the secondary reactor is
highly selective for cracking C4 and naphtha range hydrocarbons to
produce light olefins. The common catalyst regeneration provides
for heat balance, and the common product separation (disengagement
vessel and/or product fractionation systems, etc.) provides for
simplicity of operations and reduced piece count, among other
advantages.
Referring now to FIG. 1, a simplified process flow diagram of
systems for cracking hydrocarbons and producing light olefins
according to embodiments disclosed herein is illustrated. The
system includes a two-reactor configuration for maximizing yield of
propylene and ethylene from petroleum residue feedstocks or other
hydrocarbon streams. The first reactor 3 may be a riser reactor for
cracking heavier hydrocarbon feeds, for example. The second reactor
32 is a fluidized bed reactor, which may be equipped with baffles
or internals. The C.sub.4 olefins and/or light naphtha products
from the first reactor 3 or similar feed streams from external
sources may be processed in the second reactor 32 to enhance the
yield of light olefins, including propylene and ethylene, and
aromatics/high octane gasoline.
A heavy petroleum residue feed is injected through one or more feed
injectors 2 located near the bottom of first reactor 3. The heavy
petroleum feed contacts hot regenerated catalyst introduced through
a J-bend 1. The catalyst fed to the first reactor 3 is a catalyst
mixture, including a first catalyst selective for cracking heavier
hydrocarbons, such as a Y-type zeolite based catalyst, and a second
catalyst selective for the cracking of C.sub.4 and naphtha range
hydrocarbons for the production of light olefins, such as a ZSM-5
or ZSM-11, which may also be used in combination with other
catalysts. The first and second catalysts may be different in one
or both particle size and density. A first catalyst, such as the
Y-type based zeolite, may have a particle size in the range of
20-200 microns and an apparent bulk density in the range of
0.60-1.0 g/ml. A second catalyst, such as ZSM-5 or ZSM-11, may have
a particle size in the range of 20-350 microns and an apparent bulk
density in the range of 0.7-1.2 g/ml.
The heat required for vaporization of the feed and/or raising the
temperature of the feed to the desired reactor temperature, such as
in the range from 500.degree. C. to about 700.degree. C., and for
the endothermic heat (heat of reaction) may be provided by the hot
regenerated catalyst coming from the regenerator 17. The pressure
in first reactor 3 is typically in the range from about 1 barg to
about 5 barg.
After the major part of the cracking reaction is completed, the
mixture of products, unconverted feed vapors, and spent catalyst
flow into a two stage cyclone system housed in cyclone containment
vessel 8. The two-stage cyclone system includes a primary cyclone
4, for separating spent catalyst from vapors. The spent catalyst is
discharged into stripper 9 through primary cyclone dip leg 5. Fine
catalyst particles entrained with the separated vapors from primary
cyclone 4 and product vapors from second reactor 32, introduced via
flow line 36a and a single stage cyclone 36c, are separated in
second stage cyclone 6. The catalyst mixture collected is
discharged into stripper 9 via dip leg 7. The vapors from second
stage cyclone 6 are vented through a secondary cyclone outlet 12b,
which may be connected to plenum 11, and are then routed to a main
fractionator/gas plant (not shown) for recovery of products,
including the desired olefins. If necessary, the product vapors are
further cooled by introducing light cycle oil (LCO) or steam via
distributor line 12a as a quench media.
The spent catalyst recovered via dip legs 5, 7 undergoes stripping
in stripper bed 9 to remove interstitial vapors (the hydrocarbon
vapors trapped between catalyst particles) by countercurrent
contacting of steam, introduced to the bottom of stripper 9 through
a steam distributor 10. The spent catalyst is then transferred to
regenerator 17 via the spent catalyst standpipe 13a and lift line
15. Spent catalyst slide valve 13b, located on spent catalyst
standpipe 13a is used for controlling catalyst flow from stripper 9
to regenerator 17. A small portion of combustion air or nitrogen
may be introduced through a distributor 14 to help smooth transfer
of spent catalyst.
Coked or spent catalyst is discharged through spent catalyst
distributor 16 in the center of the dense regenerator bed 24.
Combustion air is introduced by an air distributor 18 located at
the bottom of regenerator bed 24. Coke deposited on the catalyst is
then burned off in regenerator 17 via reaction with the combustion
air. Regenerator 17, for example, may operate at a temperature in
the range from about 640.degree. C. to about 750.degree. C. and a
pressure in the range from about 1 barg to about 5 barg. The
catalyst fines entrained along with flue gas are collected in first
stage cyclone 19 and second stage cyclone 21 and are discharged
into the regenerator catalyst bed through respective dip legs 20,
22. The flue gas recovered from the outlet of second stage cyclone
21 is directed to flue gas line 50 via regenerator plenum 23 for
downstream waste heat recovery and/or power recovery.
A first part of the regenerated catalyst mixture is withdrawn via
regenerated catalyst standpipe 27, which is in flow communication
with J bend 1. The catalyst flow from regenerator 17 to reactor 3
may be regulated by a slide valve 28 located on regenerated
catalyst standpipe 27. The opening of slide valve 28 is adjusted to
control the catalyst flow to maintain a desired top temperature in
reactor 3.
In addition to lift steam, a provision is also made to inject feed
streams such as C.sub.4 olefins and naphtha or similar external
streams as a lift media to J bend 1 through a gas distributor 1a
located at the Y-section for enabling smooth transfer of
regenerated catalyst from J bend 1 to reactor 3. J bend 1 may also
act as a dense bed reactor for cracking C.sub.4 olefins and naphtha
streams into light olefins at conditions favorable for such
reactions, such as a WHSV of 0.5 to 50 h.sup.-1, a temperature of
640.degree. C. to 750.degree. C., and residence times from 3 to 10
seconds.
A second part of the regenerated catalyst mixture is withdrawn into
a second reactor 32 through a standpipe 30. A slide valve 31 may be
used to control the catalyst flow from regenerator 17 to second
reactor 32 based on a vapor outlet temperature set point. C.sub.4
olefins and naphtha streams are injected into the bottom section of
the catalyst bed through one or more feed distributors 34 (34a,
34b), either in liquid or vapor phase. Second reactor 32 operates
in a mixed flow fashion, where a portion of the regenerated
catalyst flows downward (from the top to the bottom of the reactor
bed) and a portion of the regenerated catalyst mixture and the feed
hydrocarbon stream flows upward (from the bottom to the top of the
reactor bed).
Second reactor 32 may be equipped with baffles or structured
internals (not shown) that help intimate contact and mixing of
catalyst and feed molecules. These internals may also help in
minimizing channeling, bubble growth, and/or coalescence. Second
reactor 32 may also be enlarged at different sections along the
length to maintain a constant or desired superficial gas velocity
within the sections.
After the reaction is completed, the catalyst is stripped at the
bottommost portion of second reactor 32 to separate entrained
hydrocarbon feed/products using steam as a stripping media
introduced through distributor 35. The spent catalyst recovered at
the bottom of reactor 32 is then transferred to regenerator 17 via
standpipe 37 and lift line 40 through a spent catalyst distributor
41. Combustion air or nitrogen may be introduced through
distributor 39 to enable smooth transfer of catalyst to regenerator
17. Slide valve 38 may be used to control the catalyst flow from
second reactor 32 to regenerator 17. Spent catalyst from both
reactors 3, 32 is then regenerated in the common regenerator 17,
operating in a complete combustion mode.
As noted above, second reactor 32 utilizes two different catalysts
that may differ in one or both of particle size and density, such
as a lighter and smaller Y-type zeolite or FCC catalyst and a
larger and/or denser ZSM-5/ZSM-11 shape-selective pentacil small
pore zeolite. The superficial gas velocity in second reactor 32 is
maintained such that essentially all or a large portion of the
lighter, smaller catalyst (e.g., Y-type zeolite/FCC catalyst) and a
portion of the heavier, larger catalyst (e.g., ZSM-5/ZSM-11) is
carried out of the reactor with the cracked hydrocarbons and steam
recovered via flow line 45. A portion of the larger and/or denser
catalyst may be retained within the reactor 32, forming a dense bed
toward the lower portion of the reactor, as noted above.
The effluent from reactor 32 recovered via flow line 45 may thus
include cracked hydrocarbon products, unreacted hydrocarbon
feedstock, steam (stripping media), and a catalyst mixture,
including essentially all of the lighter and/or smaller catalyst
and a portion of the larger and/or more dense catalyst introduced
to the reactor. The effluent may then be transported via flow line
45 to a solids separator 47. Separator 47 may be a separator
configured to separate the two types of catalyst based on their
physical properties, namely particle size and/or density. For
example, separator 47 may use differences in inertial forces or
centrifugal forces to separate FCC catalyst from the ZSM-5. The
solids separation vessel 47 is an external vessel to the second
reactor 32 and is operated at hydrodynamic properties that enhance
the separation of the two types of catalyst based on their physical
properties.
After separation in separator 47, the smaller and/or lighter
catalyst (Y-type zeolite/FCC catalyst) is then transported from
separator 47 to the common disengager or containment vessel 8,
housing the riser reactor cyclones and/or reaction termination
system, via outlet line 36a. The larger and/or denser catalyst
(ZSM-5/ZSM-11) may be returned via flow line 49 to the mixed flow
reactor 32 for continued reaction with hydrocarbon feeds introduced
through distributors 34.
Entrainment of essentially all of the lighter/smaller catalyst and
a portion of the larger and/or more dense catalyst, subsequent
separations, and recycle of the larger and/or denser catalyst to
reactor 32 may allow for a significant accumulation of the larger
and/or denser catalyst in reactor 32. As this catalyst is more
selective for the cracking of C.sub.4 and naphtha range
hydrocarbons, the accumulation of the larger and/or denser catalyst
may provide a selectivity and yield advantage. Further, operation
of the reactor in a fluidization flow regime to entrain both types
of catalyst may provide for improved operability of the reactor or
flexibility in operations, as discussed above.
A hydrocarbon feed such as heavy vacuum gas oil or heavy residue
feed, light cycle oil (LCO), or steam may be injected as a quench
media in the outlet line 36a through a distributor 36b. The flow
rate of such quench media may be controlled by setting the
temperature of the stream entering the containment vessel 8. All
the vapors from second reactor 32, including those fed through
distributor 36b, are discharged into the dilute phase of
containment vessel 8 through a single stage cyclone 36c. Employing
a hydrocarbon feed as a quench media is preferred as it serves dual
purpose of cooling the products from second reactor 32 and also
enhances the production of middle distillates.
The first stage reactor 3, such as a riser reactor, may operates in
the fast fluidization regime (e.g., at a gas superficial velocity
in the range from about 3 to about 10 m/s at the bottom section)
and pneumatic transport regime (e.g., at a gas superficial velocity
in the range from about 10 to about 20 m/s) in the top section.
WHSV in second reactor 32 is typically in the range from about 0.5
h.sup.-1 to about 50 h.sup.-1; vapor and catalyst residence times
may vary from about 2 to about 20 seconds. When different feeds are
introduced, preferably the C.sub.4 feed is injected at an elevation
below naphtha feed injection. However, interchanging of feed
injection locations is possible.
As necessary, make-up catalyst may be introduced via one or more
flow lines 42, 43. For example, fresh or make-up FCC or Y-type
zeolite catalyst or a mixture of these two may be introduced to
regenerator 17 via flow line 42 and fresh or make-up ZSM-5/ZSM-11
catalyst may be introduced to second reactor 32 via flow line 43.
Overall system catalyst inventory may be maintained by withdrawing
mixed catalyst from regenerator 24, for example. Catalyst inventory
and accumulation of the preferred catalyst within reactor 32 may be
controlled, as will be described below, via control of the reactor
and separator 47 operations.
In some embodiments, a first part of the regenerated catalyst is
withdrawn from regenerator 17 into a Regenerated Catalyst (RCSP)
hopper 26 via withdrawal line 25, which is in flow communication
with regenerator 17 and regenerated catalyst standpipe 27. The
catalyst bed in the RCSP hopper 26 floats with regenerator 17 bed
level. The regenerated catalyst is then transferred from RCSP
hopper 26 to reactor 3 via regenerated catalyst standpipe 27, which
is in flow communication with J bend 1. The catalyst flow from
regenerator 17 to reactor 3 may be regulated by a RCSP slide valve
28 located on regenerated catalyst standpipe 27. A pressure
equalization line 29 may also be provided.
A separator bypass line 60 may also be used to facilitate the
transfer of particles from the top of reactor 32 to the vessel 8,
such as illustrated in FIG. 1. As described with respect to FIG. 1
above, second reactor 32 utilizes two different catalysts that may
differ in one or both of particle size and density, such as a
lighter and/or smaller Y-type zeolite or FCC catalyst and a larger
and/or denser ZSM-5/ZSM-11 shape-selective pentacil small pore
zeolite. The superficial gas velocity in second reactor 32 may be
maintained such that essentially all of the lighter, smaller
catalyst (e.g., Y-type zeolite/FCC catalyst) and a portion of
larger and/or more dense catalyst (e.g., ZSM-5/ZSM-11) is carried
out of the reactor with the cracked hydrocarbons and steam
recovered via flow line 45.
The effluent from reactor 32 recovered via flow line 45 may thus
include cracked hydrocarbon products, unreacted hydrocarbon
feedstock, steam (stripping media), and a catalyst mixture,
including essentially all of the lighter, smaller catalyst and a
portion of the larger and/or more dense catalyst introduced to the
reactor. The effluent may then be transported via flow line 45 to a
solids separator 47. Separator 47 may be a separator configured to
separate the two types of catalyst based on their physical
properties, namely particle size and/or density. The separator 47
is operated at hydrodynamic properties that enhance the separation
of the two types of catalyst based on their physical
properties.
After separation in separator 47, the smaller/lighter catalyst
(Y-type zeolite/FCC catalyst) is then transported from separator 47
to the common disengager or containment vessel 8, housing the riser
reactor cyclones and/or reaction termination system, via outlet
line 36a. The larger and/or denser catalyst (ZSM-5/ZSM-11) may be
returned to the mixed flow reactor 32 for continued reaction with
hydrocarbon feeds introduced through distributors 34.
Continuously or intermittently, a portion of the effluent
containing both types of catalysts being transported via flow line
45 may be diverted to bypass separator 47. The diverted portion of
the effluent may flow around separator 47 via flow line 60, which
may include a diverter or flow control valve 62. The effluent may
then continue via flow line 64 back to disengager 8 for separation
of the hydrocarbon products from the catalysts. Flow line 64 may be
combined with the effluent and smaller catalyst recovered from
separator 47 via flow line 36a, and may be introduced either
upstream or downstream of quench 36b. Alternatively, the diverted
effluent in line 60 may be fed directly to disengager/containment
vessel 8.
While illustrated in FIG. 1 with a diverter valve 62, embodiments
herein contemplate use of y-shaped flow conduit or similar
apparatus to continuously send a portion of the effluent,
containing both catalyst particle types, to disengager 8, while
continuously sending a portion of the effluent to separator 47,
thus allowing for the desired accumulation of the larger and/or
denser catalyst particles within reactor 32. As depicted in FIG. 1,
the catalyst from second reactor can also be transferred via line
37, slide valve 38 and transfer line 40 to the regenerator 17. The
blower air is used as carrier gas 39 to transfer the catalyst to
regenerator 17. Such catalyst transfer facility will not only help
in controlling the catalyst bed level in reactor 32 but also help
in more frequent catalyst regeneration.
The use of increased flow of carrier fluid and/or the use of a flow
diverter, as described above, may beneficially provide for the
accumulation of the catalyst selective for cracking naphtha range
hydrocarbons in the second reactor, reactor 32. In some
embodiments, it has been found that reactor 32 may be operated in a
manner to provide regenerated catalyst and maintain sufficient
activity within the catalyst bed of reactor 32 such that the
catalyst transfer line (flow lines 37, 40) and the associated
equipment may be omitted from the flow scheme (as shown in FIG. 6)
without detriment to the selectivity and throughput of the reactor
and with the added benefits of reduced mechanical complexity and
reduced capital and operating costs.
Referring now to FIG. 6, a simplified process flow diagram of
systems for cracking hydrocarbons and producing light olefins
according to embodiments disclosed herein is illustrated, where
like numerals represent like parts. Similar to the process scheme
illustrated in FIG. 1, described above, the system as illustrated
in FIG. 6 will have a two reactor scheme and introduce two kinds of
particles (such as a lighter and/or smaller Y-type or FCC catalyst
and a larger and/or denser ZSM-5 or ZSM-11 catalyst) in the
secondary reactor 32. The larger and/or denser catalyst additives
(e.g., ZSM-5 or ZSM-11) may be added directly to the secondary
reactor vessel 32 via flow line 43. The regenerated catalyst
mixture transfers from regenerator 17 through pipe 30 to the
reactor vessel 32.
The catalyst bed in the secondary reactor vessel 32 is expected to
operate in turbulent bed, bubbling bed or fast fluidization
regimes. A light naphtha feed 34a, such as the light naphtha
product from a primary reactor or riser reactor 3, as illustrated,
may be fed into the secondary reactor 32 and converted to light
olefins in the presence of the mixed catalyst. The lifting gas
along with product gas in the vessel 32 will lift the solids,
including both catalysts, through the pipe 45 to the solids
separation vessel 47, then back to the regenerator 17. Due to the
differences in size and/or density of the two catalyst particles,
most of the ZSM-5 or ZSM-11 catalyst particles will be separated
from the Y-type or FCC catalyst in the solids separation vessel 47
and transferred via return line 49 back to the reactor 32. Most of
Y-type or FCC catalyst particles will be transferred back to the
stripper 8 for gas solid separation.
As compared to other embodiments discussed above, a primary
difference is the absence of a catalyst return line and related
control valves and equipment from the bottom of the secondary
reactor vessel 32 back to the regenerator vessel 17. As discussed
briefly above, such a process configuration may still provide for
efficient catalyst regeneration, as well as accumulation and
concentration of the desired larger and/or denser ZSM-5 or ZSM-11
catalyst within reactor 32. It is expected that a higher
concentration of the larger and/or denser catalyst may result in a
better performance in the secondary reactor vessel 32, even when
the return line 37 is removed. This design, with the removal of
return line 37, also mitigates the mechanical complexity and
reduces the capital and operational costs.
The embodiment without a return line 37 (FIG. 6) also includes
steam as a lifting gas. As there is no catalyst outlet at the
bottom of the reactor 32, the catalyst will fill up the reactor 32
and in some embodiments no catalyst bed level is observed. The
lifting gas along with product gas in the vessel 32 will lift the
solids, including both catalysts, through the pipe 45 to the solids
separation vessel 47. Due to the differences in size and/or density
of the two catalyst particles, most of the ZSM-5 or ZSM-11 catalyst
particles will be separated from the Y-type or FCC catalyst in the
solids separation vessel 47 and transferred via return line 49 back
to the reactor 32. Most of Y-type or FCC catalyst particles will be
transferred back to the stripper 8 for gas solid separation. As
compared to FIG. 1, this design without return line 37 may lead to
a much higher concentration of the larger and/or denser catalyst,
which will result in a better reaction performance in the reactor
32. Although not illustrated, vessel 32 may include a bottom flange
or outlet allowing the vessel to be de-inventoried of catalyst.
Such an outlet may also be used to periodically remove larger
and/or heavier catalyst particles that may accumulate within vessel
32, if necessary.
As described above, systems according to embodiments herein may
include a separator 47 configured to separate the two types of
catalysts based on their physical properties, such as particle size
and/or density. Separator 47 may be a cyclone separator, a screen
separator, mechanical sifters, a gravity chamber, a centrifugal
separator, a baffle chamber, a louver separator, an in-line or
pneumatic classifier, or other types of separators useful for
efficiently separating particles based on size and/or hydrodynamic
properties.
Examples of separators or classifiers useful in embodiments herein
are illustrated in FIGS. 2-5. In some embodiments, separator 47 may
be a U-shaped inertial separator, as illustrated in FIG. 2, to
separate two kinds of solid particles or catalysts with different
particle sizes and/or particle density. The separator may be built
in the form of U-shape, having an inlet 70 at the top, a gas outlet
84 at the other end of the U, and a main solid outlet 80 at the
base of U-shaped separator.
A mixture 72 of solid particles or catalysts with different sizes
is introduced along with a carrier gas stream through inlet 70 and
inertial separation forces are applied on the solids by making no
more than one turn to separate the different sizes of solid
particles. Larger and/or more dense solid particles 78
preferentially go downward in sections 74/76 to a standpipe or
dipleg 80 connected to the base of U-shape while lighter or smaller
solid particles are preferentially carried along with the gas
stream to outlet 82, where the mixture 84 of small particles and
gases may be recovered. The solid outlet 80 at the base of U-shaped
separator (the inlet of the standpipe or dipleg used to flow the
larger and/or more dense catalyst particles back to the second
reactor 32) should be large enough to accommodate the normal
solid/catalyst flow.
By controlling the gas flow rates entering the downward standpipe
and exiting the main gas stream outlet, the overall separation
efficiency of the U-shape inertial separator and the selectivity to
separate larger and/or more dense particles from smaller and/or
less dense particles can be manipulated. This extends to a fully
sealed dipleg where the only gas stream exiting the dipleg are
those entrained by the exiting solid/catalyst flow. As the U-shaped
inertial separator provides the ability to manipulate the
separation efficiency, intermediate sized particles, which have the
potential to accumulate in the system as noted above, may be
periodically or continuously entrained with the hydrocarbon
products recovered from separator 47 for separation in vessel 8 and
regeneration in regenerator 24.
In some embodiments, a gas sparger 75 or extra steam/inert gas may
be provided proximate a top of outlet section 80, such as near a
top of the standpipe inlet. The additional lift gas provided within
the separator may further facilitate the separation of larger
and/or more dense solid particles from less dense and/or smaller
solid particles, as the extra gas may preferentially lift lighter
solid particles to gas outlet 84, resulting in better solid
classification.
The cross sectional area of the U-shaped separator at the inlet 70,
outlet 82 and throughout the U-shaped separator (including areas
74, 76) may be adjusted to manipulate the superficial gas velocity
within the apparatus to control the separation efficiency and the
selectivity. In some embodiments, a position of one or more of the
separator walls may be adjustable, or a movable baffle may be
disposed within one or more sections of the separator, which may be
used to control the separation efficiency and selectivity. In some
embodiments, the system may include a particle size analyzer
downstream of outlet 82, enabling real-time adjustment of the flow
configuration through the U-shaped separator to effect the desired
separations.
Utilization of U-shaped inertial separators connected in series or
a combination of U-shape inertial separators and cyclones may
provide flexibility to allow simultaneously achievement of both
target overall separation efficiency and target selectivity of
larger and/or more dense particles over smaller and/or less dense
particles.
The secondary reactor 32 may also be equipped with baffles or
structured internals such as modular grids as described in U.S.
Pat. No. 7,179,427. Other types of internals that enhance contact
efficiency and product selectivity/yields may also be used. The
internals may enhance the catalyst distribution across the reactor
and improve the contact of feed vapors with catalyst, leading to an
increase in the average reaction rate, enhance the overall activity
of the catalyst and optimize the operating conditions to increase
the production of light olefins.
Embodiments disclosed herein use Y-type zeolite or conventional FCC
catalyst, maximizing the conversion of heavy hydrocarbon feeds. The
Y-type zeolite or FCC catalyst is of a smaller and/or lighter
particle size than the ZSM-5 or similar catalysts used to enhance
the production of light olefins in the countercurrent flow reactor.
The ZSM-5 or similar catalysts have a larger particle size and/or
are more dense than the Y-type zeolite or FCC catalysts used to
enhance separations of the catalyst types in each of the mixed flow
reactor and the solids separator. The superficial gas velocity of
vapors in the second reactor is maintained such that it allows
entrainment of the Y-type zeolite or FCC catalyst and a portion of
the ZSM-5 or ZSM-11 catalyst out of the mixed flow reactor, and the
solids separator may utilize the differences in single particle
terminal velocities or differences between minimum
fluidization/minimum bubbling velocities to separate and return the
ZSM-5/ZSM-11 to the mixed flow reactor. This concept allows the
elimination of two stage FCC systems and hence a simplified and
efficient process. The catalysts employed in the process could be
either a combination of Y-type zeolite/FCC catalyst and ZSM-5 or
other similar catalysts, such as those mentioned in U.S. Pat. Nos.
5,043,522 and 5,846,402.
The entrainment of both catalysts from the mixed flow reactor,
subsequent separation, and recycle and accumulation of the
ZSM-5/ZSM-11 catalyst in the mixed flow reactor eliminates any
potential restriction on superficial gas velocity in the secondary
reactor. The use of a solids separation vessel thus provides
process flexibility in the secondary reactor, allowing the
secondary reactor to be operated in bubbling bed, turbulent bed, or
fast fluidization regimes, rather than restricting the operations
to only a bubbling bed regime. The solids separation vessel may be
a cyclone or other vessel where solids and gases are introduced at
a common inlet, and through degassing, inertial and centrifugal
forces, the particles are separated based on size and/or density,
with the majority of the smaller FCC type particles entraining with
the vapor outlet, and the larger and/or denser ZSM-5 or ZSM-11 type
particles returning via a dense phase standpipe or dipleg back to
the secondary reactor vessel 32.
In addition to the U-type particle separator described in relation
to FIG. 2, FIGS. 3-5 illustrate various additional particle
separation devices for use in embodiments herein. Referring to FIG.
3, a baffle chamber separator 900 for separating catalysts or other
particles based on size and/or density may include an inlet 910,
such as a horizontal conduit. The vapors and particles contained in
the horizontal conduit then enter a chamber 912, before being
deflected by a baffle 914. The chamber 912 is connected to a first
vertical outlet 916 and a first horizontal outlet 918. The baffle
914 may be located in the middle of chamber 912, proximate the
inlet 910, or proximate the horizontal outlet 918 of the chamber.
The baffle may be at an angle or moveable such that the baffle may
be used to deflect more or less catalyst particles, and may be
configured for a particular mixture of particles.
Processes herein may utilize the baffle chamber separator 900 to
segregate larger and/or denser particles from smaller and/or less
dense particles contained in a carrier gas, such as a hydrocarbon
reaction effluent. The baffle chamber separator 900 may be
configured to: separate at least a portion of a second particle
type from the carrier gas and a first particle type, recover the
second particle type via the first vertical outlet 916 and recover
a mixture including the carrier gas and the first particle type via
the first horizontal outlet 918. The separator may also include a
distributor (not illustrated) disposed within or proximate the
first vertical outlet for introducing a fluidizing gas,
facilitating additional separation of the first particle type from
the second particle type.
Referring now to FIG. 4, a louver separator for use in accordance
with embodiments herein is illustrated. Similar to other separators
illustrated and described, the louver separator 1000 may be used
for separating catalysts or other particles based on size and/or
density. The louver separator 1000 may include a vertical inlet
1010 connected to a chamber 1012 where one or more vertical sides
1014 of the chamber are equipped with narrow slot outlets 1016,
which may be described as louvers. The number of louvers may vary
depending on the application, such as the desired particle mixture
to be separated, and the angle of the louver may be adjustable in
order to control the amount of vapor passing through and leaving
the louver outlets. The chamber 1012 is also connected to a first
vertical outlet 1014 at the bottom of the chamber.
Processes herein may utilize the louver separator 1000 to segregate
larger and/or denser particles from smaller and/or less dense
particles contained in a carrier gas, such as a hydrocarbon
reaction effluent. The louver separator 1000 may be configured to:
separate at least a portion of the second particle type from the
carrier gas and the first particle type, recover the second
particle type via the first vertical outlet 1014 and recover the
carrier gas and the first particle type via the louver outlets
1016. The separator may also include a distributor (not
illustrated) disposed within or proximate the first vertical outlet
for introducing a fluidizing gas, facilitating additional
separation of the first particle type from the second particle
type.
Referring now to FIG. 5, an inertial separator 1100 for use in
accordance with embodiments herein is illustrated. Similar to other
separators illustrated and described, the inertial separator 1100
may be used for separating catalysts or other particles based on
size and/or density. The separator may include an inlet 1110 at the
top of and extending into a chamber 1112. In some embodiments, the
height or disposition of inlet 1110 within chamber 1112 may be
adjustable. The separator may also include one or more side outlets
1114, 1116, such as one to eight side outlets, and a vertical
outlet 1118. The separator may also include a distributor (not
illustrated) disposed within or proximate the vertical outlet 1118
for introducing a fluidizing gas.
A mixture 1172 of solid particles or catalysts with different sizes
is introduced along with a carrier gas stream through inlet 1110.
The gases in the mixture 1172 are preferentially directed toward
outlets 1114, 1116 based on pressure differentials, and inertial
separation forces are applied on the solids by making the particles
and carrier gas turn from the extended inlet 1110 within chamber
1112 to flow toward outlets 1114, 1116, the inertial forces
separating the different sizes/densities of particles. Larger
and/or heavier solid particles 1174 preferentially go downward in
sections 1118 to a standpipe or dipleg (not shown) connected to the
base of the separator, while lighter or smaller solid particles
1176 are preferentially carried along with the gas stream to
outlets 1114, 1116, where the mixture of small particles and gases
may be recovered.
In each of the separators described herein, by controlling the gas
flow rates entering the downward standpipe/separation chamber and
exiting the main gas stream outlet, the overall separation
efficiency of the separator and the selectivity to separate heavier
and/or larger particles from lighter or smaller particles can be
manipulated. This extends to a fully sealed dipleg where the only
gas stream exiting the dipleg are those entrained by the exiting
solid/catalyst flow.
In some embodiments, a gas sparger or extra steam/inert gas may be
provided proximate a top of the heavy/dense particle outlet
section, such as near a top of the standpipe inlet. The additional
lift gas provided within the separator may further facilitate the
separation of heavier and/or larger solid particles from lighter or
smaller solid particles, as the extra gas may preferentially lift
lighter solid particles to the gas outlets, resulting in better
solid classification.
The particle separators described herein may be disposed external
or internal to a vessel. Further, in some embodiments, the
large/dense particle outlets of the particle separators may be
fluidly connected to an external vessel, providing for selective
recycle or feed of the separated particles to the desired reactor,
so as to maintain a desired catalyst balance, for example.
Embodiments disclosed herein, by the methods described above,
significantly increase the concentration of desired catalysts in
the secondary reactor (vessel 32), consequently increasing light
olefin yield. In addition, this process also serves as a method to
decouple the withdrawal and addition of the ZSM-5 and ZSM5-11 with
the withdrawal and addition of FCC catalyst. In summary, the FCC
process presented in this disclosure creates a desired ZSM-5 or
ZSM-11 catalyst additive rich environment in the secondary reactor
32, which could preferentially convert light naphtha products, such
as those derived from primary reactor, to improve light olefin
yield while simultaneously maximizing middle distillate yield by
applying optimum operation condition in the primary reactor or
riser.
Another benefit of embodiments disclosed herein is that the
integrated two-reactor scheme overcomes the heat balance
limitations in the stand alone C.sub.4/naphtha catalytic cracking
processes. The secondary (mixed flow) reactor acts as a heat sink
due to integration with the catalyst regenerator, minimizing the
requirement of catalyst cooler while processing residue feed
stocks.
The product vapors from the secondary reactor are transported into
the first stage reactor/disengaging vessel or reaction termination
device wherein these vapors are mixed and quenched with the
products from the first stage and or external quench media such as
LCO or steam to minimize the unwanted thermal cracking reactions.
Alternatively, the product outlet line of the secondary
reactor/solids separator can also be used to introduce additional
quantity of heavy feed or re-route part of the feed from the first
stage reactor (the riser reactor). This serves two purposes: (1)
the catalyst in the solids separator vapor outlet line is
predominantly Y-type zeolite/conventional FCC catalyst that is
preferred to crack these heavy feed molecules into middle
distillates, and (2) such cracking reaction is endothermic that
helps in reducing the temperature of the outgoing product vapors
and also residence time.
In some embodiments disclosed herein, an existing FCC unit may be
retrofitted with a secondary reactor as described above. For
example, a properly sized reactor may be fluidly connected to an
existing catalyst regeneration vessel to provide catalyst feed and
return from the mixed flow vessel, and fluidly connected to an
existing disengagement vessel to separate the hydrocarbon products
and catalysts. In other embodiments, a mixed flow reactor may be
added to a grass-roots FCC unit that is aimed at operating in
gasoline mode, light olefins mode, or diesel mode.
The reactor system described above with respect to FIGS. 1 and 6
related primarily to light olefins production, and advantageous
concentration of a catalyst in a mixed catalyst system to enhance
reactivity and selectivity of the system. Such a reactor system may
also be used for other mixed catalyst systems, where concentration
of one of the catalysts may be advantageous.
For example, in some embodiments, the reaction system may be used
for gasoline desulfurization, where catalyst mixture may include a
smaller and/or less dense FCC catalyst, such as zeolite Y, and a
larger and/or denser catalyst, such as a gasoline desulfurization
additive. Such a process is described with respect to FIG. 7.
Referring now to FIG. 7, a simplified process flow diagram of
systems for cracking and desulfurizing hydrocarbons according to
embodiments disclosed herein is illustrated. The system includes a
two-reactor configuration for producing olefins, such as propylene
and ethylene, from petroleum feedstocks or other hydrocarbon
streams. The first reactor 3 may be a riser reactor for cracking
heavier hydrocarbon feeds, for example. The second reactor 32 is a
fluidized bed reactor, which may be equipped with baffles or
internals. The cracked hydrocarbon products, including olefins
and/or light naphtha products from the first reactor 3 or similar
feed streams from external sources, may be processed in the second
reactor 32 to enhance the quality of the product, such as
decreasing the overall sulfur content of the hydrocarbons processed
in the second reactor.
A heavy petroleum residue feed is injected through one or more feed
injectors 2 located near the bottom of first reactor 3. The heavy
petroleum feed contacts hot regenerated catalyst introduced through
a J-bend 1. The catalyst fed to the first reactor 3 is a catalyst
mixture, including a first catalyst selective for cracking heavier
hydrocarbons, such as a Y-type zeolite based catalyst, and a second
catalyst selective for the desulfurization of naphtha range
hydrocarbons, which may also be used in combination with other
catalysts. The first and second catalysts may be different in one
or both particle size and density.
The heat required for vaporization of the feed and/or raising the
temperature of the feed to the desired reactor temperature, such as
in the range from 500.degree. C. to about 700.degree. C., and for
the endothermic heat (heat of reaction) may be provided by the hot
regenerated catalyst coming from the regenerator 17.
After the major part of the cracking reaction is completed, the
mixture of products, unconverted feed vapors, and spent catalyst
flow into a two stage cyclone system housed in cyclone containment
vessel 8. The two-stage cyclone system includes a primary cyclone
4, for separating spent catalyst from vapors. The spent catalyst is
discharged into stripper 9 through primary cyclone dip leg 5. Fine
catalyst particles entrained with the separated vapors from primary
cyclone 4 and product vapors from second reactor 32, introduced via
flow line 36a and a single stage cyclone 36c, are separated in
second stage cyclone 6. The catalyst mixture collected is
discharged into stripper 9 via dip leg 7. The vapors from second
stage cyclone 6 are vented through a secondary cyclone outlet 12b,
which may be connected to plenum 11, and are then routed to a
fractionator/gas plant 410 for recovery of products, including the
desired olefins. If necessary, the product vapors are further
cooled by introducing light cycle oil (LCO) or steam via
distributor line 12a as a quench media.
The fractionator 410 may be, for example, a main fractionator of an
FCC plant, and may produce various hydrocarbon fractions, including
a light olefin-containing fraction 412, a naphtha fraction 414, and
a heavies fraction 416, among other various hydrocarbon cuts. The
products routed to fractionator/gas plant 410 may include other
light gases, such as hydrogen sulfide that may be produced during
desulfurization; Separators, absorbers, or other unit operations
may be included where such impurities are desired to be separated
upstream of the main fractionator/gas plant.
The spent catalyst recovered via dip legs 5, 7 undergoes stripping
in stripper bed 9 to remove interstitial vapors (the hydrocarbon
vapors trapped between catalyst particles) by countercurrent
contacting of steam, introduced to the bottom of stripper 9 through
a steam distributor 10. The spent catalyst is then transferred to
regenerator 17 via the spent catalyst standpipe 13a and lift line
15. Spent catalyst slide valve 13b, located on spent catalyst
standpipe 13a, is used for controlling catalyst flow from stripper
9 to regenerator 17. A small portion of combustion air or nitrogen
may be introduced through a distributor 14 to help smooth transfer
of spent catalyst.
Coked or spent catalyst is discharged through spent catalyst
distributor 16 in the center of the dense regenerator bed 24.
Combustion air is introduced by an air distributor 18 located at
the bottom of regenerator bed 24. Coke deposited on the catalyst is
then burned off in regenerator 17 via reaction with the combustion
air. The catalyst fines entrained along with flue gas are collected
in first stage cyclone 19 and second stage cyclone 21 and are
discharged into the regenerator catalyst bed through respective dip
legs 20, 22. The flue gas recovered from the outlet of second stage
cyclone 21 is directed to flue gas line 50 via regenerator plenum
23 for downstream waste heat recovery and/or power recovery.
A first part of the regenerated catalyst mixture is withdrawn via
regenerated catalyst standpipe 27, which is in flow communication
with J bend 1. The catalyst flow from regenerator 17 to reactor 3
may be regulated by a slide valve 28 located on regenerated
catalyst standpipe 27. The opening of slide valve 28 is adjusted to
control the catalyst flow to maintain a desired top temperature in
reactor 3.
In addition to lift steam, a provision is also made to inject feed
streams such as C.sub.4 olefins and naphtha or similar external
streams as a lift media to J bend 1 through a gas distributor 1a
located at the Y-section for enabling smooth transfer of
regenerated catalyst from J bend 1 to reactor 3. J bend 1 may also
act as a dense bed reactor for cracking C.sub.4 olefins and naphtha
streams into light olefins at conditions favorable for such
reactions.
A second part of the regenerated catalyst mixture is withdrawn into
a second reactor 32 through a standpipe 30. A valve 31 may be used
to control the catalyst flow from regenerator 17 to second reactor
32 based on a vapor outlet temperature set point. One or more
hydrocarbon fractions, such as naphtha streams, may be injected
into the bottom section of the catalyst bed through one or more
feed distributors 34 (34a, 34b), either in liquid or vapor phase.
In some embodiments, the naphtha feed may include a portion or all
of the naphtha 414 from the fractionator 410. Second reactor 32
operates in a mixed flow fashion, where a portion of the
regenerated catalyst flows downward (from the top to the bottom of
the reactor bed) and/or circulates within vessel 32, and a portion
of the regenerated catalyst mixture and the feed hydrocarbon stream
flows upward (from the bottom to the top of the reactor bed, the
smaller/less dense particles carrying out of the top of the reactor
with the effluent hydrocarbons).
Second reactor 32 may be equipped with baffles or structured
internals (not shown) that help intimate contact and mixing of
catalyst and feed molecules. These internals may also help in
minimizing channeling, bubble growth, and/or coalescence. Second
reactor 32 may also be enlarged at different sections along the
length to maintain a constant or desired superficial gas velocity
within the sections.
After the reaction is completed, the catalyst is stripped at the
bottommost portion of second reactor 32 to separate entrained
hydrocarbon feed/products using steam as a stripping media
introduced through distributor 35. The spent catalyst recovered at
the bottom of reactor 32 may then be withdrawn through catalyst
withdrawal line 418. Alternatively, the spent catalyst recovered at
the bottom of reactor 32 may be transferred to regenerator 17, as
described above with respect to FIG. 1 (via standpipe 37 and lift
line 40 through a spent catalyst distributor 41, where combustion
air or nitrogen may be introduced through distributor 39 to enable
smooth transfer of catalyst to regenerator 17). A valve (not
illustrated) may be used to control the catalyst flow from second
reactor 32.
As noted above, second reactor 32 utilizes two different catalysts
that may differ in one or both of particle size and/or density,
such as a less dense and/or smaller Y-type zeolite or FCC catalyst
and a larger and/or denser desulfurization catalyst. The
superficial gas velocity in second reactor 32 is maintained such
that essentially all or a large portion of the lighter, smaller
catalyst and a portion of the larger and/or denser catalyst is
carried out of the reactor with the hydrocarbon products and steam
recovered via effluent flow line 45. A portion of the larger and/or
denser catalyst may be retained within the reactor 32, forming a
dense bed toward the lower portion of the reactor, as noted
above.
The effluent from reactor 32 recovered via flow line 45 may thus
include desulfurized hydrocarbon products, unreacted hydrocarbon
feedstock, steam (stripping media), and a catalyst mixture,
including essentially all of the lighter and/or smaller catalyst
and a portion of the heavier and/or larger catalyst introduced to
reactor 32. The effluent may then be transported via flow line 45
to a solids separator 47. Separator 47 may be a separator
configured to separate the two types of catalyst based on their
physical properties, namely particle size and/or density. For
example, separator 47 may use differences in inertial forces or
centrifugal forces to separate the smaller and/or lighter catalyst
from the larger and/or heavier catalyst. The solids separation
vessel 47 is an external vessel to the second reactor 32 and is
operated at hydrodynamic properties that enhance the separation of
the two types of catalyst based on their physical properties.
After separation in separator 47, the smaller and/or lighter
catalyst (Y-type zeolite/FCC catalyst) is then transported from
separator 47 to the common disengager or containment vessel 8,
housing the riser reactor cyclones and/or reaction termination
system, via outlet line 36a. The larger and/or heavier
desulfurization catalyst may be returned via flow line 49 to the
mixed flow reactor 32 for continued reaction with hydrocarbon feeds
introduced through distributors 34a/b.
Entrainment of essentially all of the lighter/smaller catalyst and
a portion of the heavier and/or larger catalyst, subsequent
separations, and recycle of the heavier and/or larger catalyst to
reactor 32 may allow for a significant accumulation of the larger
and/or heavier desulfurization catalyst in reactor 32. As this
catalyst is more selective for the desulfurization of naphtha range
hydrocarbons, the accumulation of the larger and/or heavier
catalyst may provide a selectivity and yield advantage. Further,
operation of the reactor in a fluidization flow regime to entrain
both types of catalyst may provide for improved operability of the
reactor or flexibility in operations, as discussed above.
A hydrocarbon feed such as heavy vacuum gas oil or heavy residue
feed, light cycle oil (LCO), or steam may be injected as a quench
media in the outlet line 36a through a distributor 36b. The flow
rate of such quench media may be controlled by setting the
temperature of the stream entering the containment vessel 8. All
the vapors from second reactor 32, including those fed through
distributor 36b, are discharged into the dilute phase of
containment vessel 8 through a single stage cyclone 36c. Employing
a hydrocarbon feed as a quench media is preferred as it serves dual
purpose of cooling the products from second reactor 32 and also
enhances the production of middle distillates.
The first stage reactor 3, such as a riser reactor, may operates in
the fast fluidization regime (e.g., at a gas superficial velocity
in the range from about 3 to about 10 m/s at the bottom section)
and pneumatic transport regime (e.g., at a gas superficial velocity
in the range from about 10 to about 20 m/s) in the top section.
WHSV in second reactor 32 is typically in the range from about 0.5
h.sup.-1 to about 50 h.sup.-1; vapor and catalyst residence times
may vary from about 2 to about 20 seconds. As necessary, make-up
catalyst may be introduced via one or more flow lines 42, 43. For
example, fresh or make-up FCC or Y-type zeolite catalyst or a
mixture of these two may be introduced to regenerator 17 via flow
line 42 and fresh or make-up gasoline desulfurization additive may
be introduced to second reactor 32 via flow line 43. Overall system
catalyst inventory may be maintained by withdrawing mixed catalyst
from regenerator 24, for example, and/or reactor 32. Catalyst
inventory and accumulation of the preferred catalyst within reactor
32 may be controlled, such as described above. Additionally, in
some embodiments, a catalyst hopper 26 may be used in conjunction
with catalyst withdrawal line 25, pressure equalization line 29,
and standpipe 27, as described above.
Similarly, the reactor system of FIG. 7 may be used for
advantageous processing of heavy hydrocarbon feedstocks, including
heavy crudes or virgin crudes. In such an embodiment, the mixed
catalyst system may include, for example, a smaller and/or less
dense FCC catalyst, such as zeolite-Y, and a larger and/or denser
heavy oil treatment additive. For example, the heavy oil treatment
additive may be one of an active matrix catalyst, a metals trapping
additive, a coarse and/or dense Ecat (equilibrium catalyst), a
matrix or binder type catalyst (such as kaolin or sand) or a high
matrix/zeolite ratio FCC catalyst, among others. The heavy oil
treatment additive may have minimal catalytic activity towards
cracking of heavier hydrocarbons and may simply supply the surface
area necessary for thermal cracking reactions to take place. The
heavy hydrocarbon feed may be introduced to reactor 32 via
distributors 43 a/b, and the system may be operated as described
above to enhance the processing of heavy hydrocarbon
feedstocks.
WHSV in the second reactor 32 when operating under heavy
hydrocarbon treatment conditions is typically in the range from
0.1-100 hr-1; vapor and particle residence times may vary from
1-400 seconds. As necessary, makeup particles may be introduced via
one or more lines 42, 43; it may be advantageous to add the FCC or
Y-type catalyst to the regenerator 17 via line 42 and the heavy oil
treatment additive via line 43 to the second reactor 32. Overall
system activity is maintained by withdrawing particles via line 418
from the second reactor 32 and from the regenerator 24. Solids
inventory and the accumulation of the preferred heavy oil treatment
additive in second reactor 32 may be controlled by additions
through line 43 and withdrawals through line 418. Operating
temperature in second reactor 32 is controlled using catalyst from
regenerator 17 line 30 via valve 31 and may range from
400-700.degree. C. In some embodiments, the product of second
reactor 32 may be essentially the feed for primary riser reactor 3.
Additionally, in some embodiments, a catalyst hopper 26 may be used
in conjunction with catalyst withdrawal line 25, pressure
equalization line 29, and standpipe 27, as described above
In general, the process flow diagrams illustrated in FIGS. 1, 6,
and 7 use the catalyst/particle separation technology to process
additional or recycle hydrocarbon feedstocks in a secondary vessel.
The catalyst mixture circulating through the system may include
catalysts selective to particular reactions, such as cracking,
desulfurization, demetalization, denitrogenation, and other, where
the catalysts of the mixture are selected to have differing
physical properties, as described above, such that a desired
catalyst may be concentrated in the secondary reactor. Regenerated
catalyst is fed to the secondary reactor/vessel which may operate
in fast fluidized, bubbling, or turbulent bed operation (depending
on application). The effluent of the secondary reactor/vessel goes
to the separator 47, where the primary and secondary catalysts are
separated based on size and/or density and the separator bottoms,
which is enriched in the secondary catalyst, is recycled back to
the secondary reactor/vessel. The secondary reactor/vessel has
optional catalyst withdrawals which may be advantageous depending
on application as well as different hydrocarbon feeds depending on
application. The concentration of the secondary catalyst may
enhance the operability, flexibility, and selectivity of the
overall reaction system.
The separator 47 as described above with respect to FIG. 2 may be
used to enhance productivity and flexibility of mixed catalyst
hydrocarbon processing systems, where the separator 47 may be
located at other advantageous locations within the system. Such
processes and systems are described further below with respect to
FIGS. 8-11, where like numerals represent like parts.
Referring now to FIG. 8A, a simplified process flow diagram of
systems for converting hydrocarbons and producing olefins according
to embodiments disclosed herein is illustrated, where like numerals
represent like parts. The process scheme of FIG. 8A adds a catalyst
holding vessel 510 which is fed regenerated catalyst from the FCC
regenerator via catalyst withdrawal line 30 and valve 31. The
holding vessel 510 may be fluidized with a fluidization medium,
such as air, nitrogen, or steam, for example, introduced via flow
line 516. The holding vessel effluent 45 is sent to the separator
47 where the mixture of catalysts is separated. The separator
bottoms 49, which is enriched in the larger and/or heavier
catalyst, is recycled back to catalyst holding vessel 510, where
the concentration of the larger and/or denser catalyst will build
up. The remaining stream 514 from the separator 510 is returned to
the disengagement vessel 8 in this embodiment. The bottoms 512 of
the holding vessel may be coupled to a slide valve (not
illustrated) which can control the feed of catalyst to secondary
reactor/vessel 32, which can be operated in a similar fashion to
that described above with respect to FIGS. 1, 6, and 7.
Advantageously, the catalyst concentrated in vessel 510 will not be
saturated with hydrocarbon and may allow for lower contact times
with catalyst in the secondary reactor/vessel 32.
FIG. 8B illustrates a system similar to that of FIG. 8A, except the
catalyst recovered from separator 47 via flow line 514 is returned
to the catalyst regenerator 17 as opposed to being forwarded to the
disengagement vessel 8. The vessel to which the catalyst in flow
line 514 is forwarded may depend upon the type of fluidization gas
introduced via flow line 516 as well as the capabilities of the
systems receiving flow from either regenerator 17 or vessel 8, via
flow lines 50 and 12b, respectively. Where the fluidization gas is
steam, for example, the catalyst in flow line 514 is preferably
forwarded to vessel 8; where the fluidization gas is air or
nitrogen, for example, the catalyst in flow line 514 is preferably
forwarded to regenerator 17.
FIGS. 8A and 8B illustrate the smaller particles recovered via flow
line 514 as being forwarded to the regenerator 17 or disengagement
vessel 8, and the larger and/or heavier particles recovered via
flow line 512 as being forwarded to secondary reactor 32.
Embodiments herein also contemplate forwarding of the smaller
and/or lighter particles recovered via the separator 47 and flow
line 514 to secondary reactor 32 while recirculating the larger
and/or heavier particles to the regenerator 17 or stripper 9.
FIGS. 8A and 8B further illustrate a system with a vessel 510
accumulating/concentrating large particles for use in the secondary
reactor. Where a single-pass separation may suffice, the
containment vessel 510 may be excluded from the system, as
illustrated in FIGS. 9A and 9B, where like numerals represent like
parts. In these embodiments, the catalyst mixture is fed directly
from the catalyst regenerator 17 via dip leg 30 to separator 47.
Air or other fluidization gases may be supplied via flow line 610,
provided at a flow rate sufficient for the inertial separations.
The smaller/lighter particles may be recovered via flow line 612
and the larger and/or heavier particles may be recovered via flow
line 614. FIG. 9A illustrates the larger and/or heavier particles
being forwarded to secondary reactor 32, whereas FIG. 9B
illustrates the smaller and/or lighter particles being forwarded to
secondary reactor 32.
FIGS. 9A and 9B illustrate return of a particle portion to the
regenerator 17. Similar to the above description with respect to
FIGS. 8A and 8B, the particles not fed to reactor 32 may be
returned to either the regenerator 17 or the disengagement vessel
8, and such may depend on the fluidization medium and/or downstream
processing capabilities.
The process schemes illustrated in FIGS. 9A and 9B use a single
pass version of the separator as opposed to those versions that
incorporate recycle to increase the concentration. In this scheme,
the regenerated catalyst is directed to the separator where either
the bottoms or overhead of the separator can be directed to the
secondary reactor. If the bottoms were to be directed, the catalyst
would be enriched based on the larger and/or denser particles. If
the overhead of the separator were to be directed to the secondary
reactor, the catalyst would be enriched in the smaller and/or less
dense particles. This scheme could also be arranged such that no
secondary reactor is present, and the separator is between the
regenerator and the primary riser reactor, concentrating a catalyst
similar to that described for the process of FIG. 11, below.
The embodiments of FIGS. 8A/B decouple the recycle catalyst from
the secondary reactor, achieving a higher concentration of the
desired catalyst in the secondary reactor, however requiring
additional capital costs. The embodiments of 6A/B also decouple the
recycle catalyst from the secondary reactor, achieving a moderate
increase in concentration of the desired catalyst as compared to
the flow scheme of FIG. 7, for example, but at a lower capital cost
than the embodiment of FIGS. 9A/B.
Referring now to FIG. 10, a simplified process flow diagram of
systems for processing hydrocarbons according to embodiments
disclosed herein is illustrated, where like numerals represent like
parts. This process schemes removes the secondary reactor and has
the separator 47 receiving an effluent from the primary riser 3.
The riser effluent, which contains a mixed catalyst, could be
directed to the separator 47 where a portion of catalyst is
recycled to the riser 3 from the separator bottoms 710, thereby
enriching the concentration of the larger and/or heavier catalyst
in the riser reactor 3. The overhead 712 of the separator 47 would
continue to the stripper vessel 8, where the hydrocarbon products
would be separated from the remaining catalyst. This configuration
could also be used with a catalyst mixture with no degree of
classification as a method of recycling spent catalyst to the riser
3.
The enriched catalyst fraction 710 may be introduced to the riser 3
upstream or downstream (as illustrated) of the regenerated catalyst
feed inlet from standpipe 27, and in some embodiments may be
introduced at one or more points along the length of the riser
reactor 3. The inlet point may be based on secondary hydrocarbon
feeds, temperature of the recirculating catalyst 710, and other
variables that may be used to advantageously process hydrocarbons
in the riser reactor 3.
The hydrocarbon products recovered from disengagement vessel
8/stripper 9 may be forwarded, as described above, to a
fractionator/gas plant 720, for separation and recovery of one or
more hydrocarbon fractions 722, 724, 726, 728, 730. One or more of
the recovered hydrocarbon fractions from the fractionator/gas plant
in embodiments herein may be recirculated to the riser reactor 3 or
secondary reactor 32 for further processing.
a simplified process flow diagram of systems for processing
hydrocarbons according to embodiments disclosed herein is
illustrated, where like numerals represent like parts. In this
process scheme, a regenerator catalyst hopper 26 is fluidly
connected to riser reactor 3. Regenerated mixed catalyst, which
contains a smaller and/or less dense catalyst and a larger and/or
denser catalyst, flows from the regenerator 17 to the regen
catalyst hopper 26. The hopper 26 is fluidized with steam and/or
air, provided by distributor 810. The overhead effluent 816 of the
hopper flows to the separator 47. In the separator 47, which is a
separation device as described previously, the catalysts are
separated, and the bottoms 814, which is enriched in the larger
and/or denser catalyst, may be fed back to the regen catalyst
hopper 26, such as when fluidized with air, or to disengagement
vessel 8, such as when fluidized with steam. This will increase the
concentration of the larger and/or denser catalyst in the regen
catalyst hopper 26. The overhead 812 of the separator 47 may be
directed to either the regenerator or the stripper vessel. The
bottom 27 of the regenerator catalyst hopper has a withdrawal with
slide valve 28 which controls the flow of catalyst which is
enriched in the larger and/or denser catalyst to the riser 3. In
this manner, the riser 3 operates with an effective higher
concentration of catalyst than the inventory in the system,
creating preferential products based on the properties of the
catalyst.
Concentration of a catalyst in the regen catalyst hopper as
described above with respect to FIG. 11 may be performed
intermittently. The system may circulate the catalyst mixture
through the riser, stripper, and regenerator, without sufficient
fluidization in the hopper 26 to entrain catalysts to the separator
47. When there is a change in the desired product mixture, the
hydrocarbon feeds, or other factors, where it may be advantageous
to operate with a higher concentration of a particular catalyst in
the catalyst mixture, the catalyst in the regen hopper 26 may be
fluidized and separated using separator 47. When factors again
change, fluidization of the catalyst hopper may be discontinued. In
this manner, the flexibility of the system with regard to products
and feed may be enhanced.
While FIGS. 10 and 11 are illustrated with a single riser, the
solids separation device may be used to enhance the performance of
a multiple riser system. For example, a two-riser system may
benefit from the concentration of one catalyst in a riser, which
may be processing different feeds than a second riser.
Embodiments herein may utilize various types of catalysts or
particles to perform desired reactions, where a common regenerator
may be used to regenerate the mixture of catalysts, and a separator
is advantageously located to enrich one or more reactors with a
particular catalyst contained in the mixture of catalysts.
Embodiments herein may be used to improve unit operations, and
enhance the selectivity and flexibility of the reaction systems,
such as for applications including light olefins production,
gasoline desulfurization, and heavy oil processing.
Light olefins production may include various light, medium, and
heavy hydrocarbon feeds to the riser, as described above. Feeds to
the second reactor 32 may include naphtha, such as straight run
naphtha or recycle cat naphtha, among other feeds. The catalyst
mixture for light olefins production may include a smaller and/or
less dense catalyst, such as an FCC catalyst (zeolite Y, for
example), and a heavier/denser catalyst, such as ZSM-5 or ZSM-11,
among other combinations. Other cracking catalysts may also be used
Various catalysts for the cracking of hydrocarbons are disclosed in
U.S. Pat. Nos. 7,375,257, 7,314,963, 7,268,265, 7,087,155,
6,358,486, 6,930,219, 6,809,055, 5,972,205, 5,702,589, 5,637,207,
5,534,135, and 5,314,610, among others.
Embodiments directed toward gasoline desulfurization may include
various light, medium, and heavy hydrocarbon feeds to the riser, as
described above. Feeds to the second reactor 32 may also include
naphtha, such as straight run naphtha or recycle cat naphtha, among
other feeds. The catalyst mixture for light olefins production may
include a smaller and/or less dense catalyst, such as an FCC
catalyst (zeolite Y, for example), and a larger and/or denser
catalyst, with desulfurization functionality such as a
MgO/Al.sub.2O.sub.3 with various metals promotion. Other
desulfurization catalysts may also be used as disclosed in U.S.
Pat. Nos. 5,482,617, 6,482,315, 6,852,214, 7,347,929 among others.
In some embodiments, the catalyst mixture may include a cracking
catalyst composition having desulfurization activity, such as those
disclosed in U.S. Pat. No. 5,376,608, among others.
Embodiments directed toward heavy oil processing may include
various light, medium, and heavy hydrocarbon feeds to the riser, as
described above. Feeds to the second reactor 32 may include
hydrocarbons or hydrocarbon mixtures having boiling points or a
boiling range above about 340.degree. C. Hydrocarbon feedstocks
that may be used with processes disclosed herein may include
various refinery and other hydrocarbon streams such as petroleum
atmospheric or vacuum residua, deasphalted oils, deasphalter pitch,
hydrocracked atmospheric tower or vacuum tower bottoms, straight
run vacuum gas oils, hydrocracked vacuum gas oils, fluid
catalytically cracked (FCC) slurry oils, vacuum gas oils from an
ebullated bed hydrocracking process, shale-derived oils,
coal-derived oils, tar sands bitumen, tall oils, bio-derived crude
oils, black oils, as well as other similar hydrocarbon streams, or
a combination of these, each of which may be straight run, process
derived, hydrocracked, partially desulfurized, and/or partially
demetallized streams. In some embodiments, residuum hydrocarbon
fractions may include hydrocarbons having a normal boiling point of
at least 480.degree. C., at least 524.degree. C., or at least
565.degree. C. The catalyst mixture for heavy hydrocarbon
processing may include a smaller and/or less dense catalyst, such
as an FCC catalyst (zeolite Y, for example), and a larger and/or
denser catalyst, such as an active matrix catalyst, a metals
trapping catalyst, a coarse/dense Ecat (equilibrium catalyst), a
matrix or binder type catalyst (such as kaolin or sand) or a high
matrix/zeolite FCC catalyst. Other cracking catalysts may also be
used, such as, for example, one or more of those disclosed in U.S.
Pat. Nos. 5,160,601, 5,071,806, 5,001,097, 4,624,773, 4,536,281,
4,431,749, 6,656,347, 6,916,757, 6,943,132, and 7,591,939, among
others.
Systems herein may also be utilized for pre-treatment of a heavy
crude or virgin crude, such as a crude oil or bitumen recovered
from tar sands. For example, reactor 32, such as that in FIG. 1 or
9, among others, may be used to pre-treat the bitumen, prior to
further processing of the treated heavy crude in downstream
operations, which may include separation in a downstream separation
system and recycle of one or more fractions for further conversion
in reactor 3. The ability to pre-treat the heavy crude with a
preferred particle within a particle or catalyst mixture may
advantageously allow integration of heavy crude processing where it
otherwise would be detrimental to catalyst and overall system
performance.
Embodiments herein describe the catalyst mixture being separated by
the separator and the effective preferential concentration of a
catalyst within the mixture in a reactor. As illustrated in the
Figures, the catalyst being concentrated in the reactor is
illustrated as being returned from the separator proximate the top
of the reactor or vessel. Embodiments herein also contemplate
return of the catalyst from the separator to a middle or lower
portion of the reactor, and where the catalyst is returned may
depend on the hydrocarbon feeds being processed, the catalyst types
in the mixture, and the desired catalyst gradient within the
reactor vessel. Embodiments herein also contemplate return of the
catalyst to multiple locations within the reactor. While providing
the ability to enhance the concentration of a particular catalyst
or particle within a mixture in a given reactor, embodiments herein
may also be used for a one catalyst system; the particle separators
and systems described herein may increase the catalyst/oil ratio,
which enhances catalytic contact time
As described above, various embodiments herein utilize a secondary
reactor operated in a fluidization regime sufficient to entrain the
first cracking catalyst, and the second cracking catalyst, with the
hydrocarbon products recovered as an effluent from the secondary
reactor overhead outlet. In some embodiments, such as illustrated
in FIG. 12, the secondary reactor may be a secondary riser reactor,
operated in a fluidization regime sufficient to entrain the first
cracking catalyst, and the second cracking catalyst, with the
hydrocarbon products recovered as an effluent from the secondary
reactor overhead outlet. In other embodiments as illustrated in
FIG. 12, the secondary reactor may be a bubbling or fluidized bed
reactor, operated in a fluidization regime sufficient to entrain
the first cracking catalyst, a portion of the second cracking
catalyst, and the hydrocarbon products. The effluent may then be
fed to a solids separation vessel to separate the cracked
hydrocarbon products and the first cracking catalyst from the
second cracking catalyst. This solids separation vessel may be an
external vessel to the reactor and may be operated at hydrodynamic
properties that enhance the separation of the two types of catalyst
based on their physical properties, such as particle size and/or
density. The separated catalyst, selective for the cracking of
C.sub.4 and naphtha range hydrocarbons, may then be returned to the
reactor for continued reaction and providing an enhanced
concentration of the catalyst selective for the cracking of C.sub.4
and naphtha range hydrocarbons within the reactor, improving
selectivity of the overall process while also improving the overall
process flexibility due to the enhanced operating window.
Referring now to FIG. 12, FIG. 12 illustrates another process
scheme according to embodiments herein, where like numerals
represent like parts. Similar to the other process schemes, such as
those illustrated in FIGS. 1 and 6, two catalysts/solid particles
are used, with the first catalyst being a smaller and/or lighter
conventional FCC catalyst and the second catalyst being a larger
and/or heavier ZSM-5 or ZSM-11 catalyst, for example.
The mixed first and second catalysts may be fed from common
regenerator 17 via flow line 30 through control valve 31 to the
bottom of secondary riser reactor 171. At the bottom of secondary
riser reactor 171, the catalyst mixes with catalyst fed via flow
line 174a, the flow of which may be regulated by control valve 174.
The catalyst in flow line 174a may have a higher concentration of
larger and/or heavier second cracking catalyst, such as ZSM-5,
which favors naphtha cracking reaction to light olefin products
such as propylene.
The mixed catalyst, having a higher concentration of larger and/or
heavier second cracking catalyst than as supplied in the mixture
from the regenerator 17, may then be contacted with hydrocarbons in
secondary riser reactor 171. For example, a naphtha feed may be
introduced via flow line 143 and lifting steam may be fed via flow
line 135. The naphtha feed may be naphtha from downstream product
fractionators, as described above, or may be a naphtha feed from
other units, such as coker naphtha, etc. The naphtha feed can also
be fed to or from different locations not shown in FIG. 12, if
desired.
The naphtha cracking reactions occur in the secondary riser reactor
171, the naphtha feed and steam feeds being sufficient to entrain
both the first and second cracking catalysts along with the cracked
hydrocarbon products. The product stream, along with the catalyst
mixture, then enters a solid separation device (SSD) 47, which may
be used to facilitate concentration of the denser and/or larger
second cracking catalyst. SSD 47 may separate the effluent from
secondary riser reactor 171 into a vapor/first cracking catalyst
stream 147a and a second cracking catalyst stream 147b. The second
cracking catalyst recovered from the separator may be recycled back
to the secondary reactor for continued reaction, as noted
above.
The cracked hydrocarbons and separated first cracking catalyst from
the secondary riser reactor may then be fed to a disengagement
vessel 170 first cracking catalyst from the cracked hydrocarbon
products. The cracked hydrocarbon products, including light
olefins, C.sub.4 hydrocarbons, naphtha range hydrocarbons, and
heavier hydrocarbons may be recovered via flow line 180, as will be
described further below, and may then be separated to recover the
desired products or product fractions. In some embodiments, the
cracked hydrocarbon products recovered via flow line 180 may be
combined with the hydrocarbons in flow line 12 and fed to a common
separation system for combined processing and recovery of the
desired products or product fractions.
In some embodiments, as illustrated in FIG. 12, SSD 47 may be
located within a disengagement vessel 170. Disengagement vessel 170
may house an internal vessel 173, receiving the larger and/or
denser second cracking catalyst from SSD 47. The annular region 178
between the internal wall of disengagement vessel 170 and the
externa wall of internal vessel 173 may receive the smaller and/or
less dense first cracking catalyst.
In SSD 47, as described above, the secondary riser reactor effluent
may be separated into a vapor/first cracking catalyst stream 147a
and a second cracking catalyst stream 147b. Based on density and/or
particle size, the catalyst stream 147b, concentrated with the
second catalyst of larger and/or heavier ZSM-5, may be fed to
standpipe 172, then enters the internal vessel 173 and eventually
is fed back to secondary riser reactor 171 through control valve
174. Internal vessel 173 may be open-ended, such that any entrained
gases that may be recovered with the catalyst stream 147b may
separate from the catalyst in the internal open-ended vessel 173,
exit the top of the open-ended vessel 173, mix with the vapors in
vessel 170, and be recovered with the products via flow line
180.
The level of catalyst in the internal vessel 173 may be controlled
by the control valve 174 and an associated controller or control
system, and the level indication may also be used to adjust a vapor
split ratio of SSD 47 to manipulate the separation efficiency of
the larger and/or more dense second cracking catalyst particles. In
this manner, conditions may be adjusted such that a portion of the
second cracking catalyst particles may carry over into the cyclone
and be recovered in the annular region, for return to the
regenerator for regeneration.
The vapor/first cracking catalyst stream 147a enters the cyclone
176, which may separate the first cracking catalyst from the
product gas. The separated particles, concentrated with smaller
and/or lighter FCC catalyst, may then be fed via dipleg 177 into
annular portion 178. The catalyst in annular portion 178 may be fed
to regenerator 17 via flow line 175a, the flow of which may be
controlled by control valve 175. The level of the catalyst in
annular region 178 may be controlled by the control valve 175.
Similar to the primary and secondary cyclones 4, 6, in
disengagement vessel 8, vessel 170 may also house additional
cyclones (not shown) to completely separate or recover product gas
from the catalyst in the vessel 170. The product gas, including
entrained gases emanating from internal vessel 173 and annular
region 178, as well as those recovered from cyclone 176, may be
recovered via plenum 179 and may be fed via flow line 180 to
product fractionation.
In addition to lift steam 135, a provision may also be made to
inject feed streams, such as C.sub.4 olefins and naphtha or similar
external streams as a lift media to secondary riser reactor 171
through a gas distributor 171a, which may be located at the
Y-section for enabling smooth transfer of regenerated catalyst from
flow lines 174a and 30 to secondary riser reactor 171. This
lowermost portion of secondary riser reactor 171 may also act as a
dense bed reactor for cracking C.sub.4 olefins and naphtha streams
into light olefins at conditions favorable for such reactions, such
as a WHSV of 0.5 to 50 h.sup.-1, a temperature of 640.degree. C. to
750.degree. C., and residence times from 3 to 10 seconds.
The integration of a transport zone 171 and a disengagement vessel
170 may be used in other embodiments described herein as well. For
example, referring to FIGS. 8A and 8B, the secondary vessel 510 and
SSD47 may be arranged similar to transport zone 171 and
disengagement vessel 170 to provide a vapor product stream 180
(514) and a concentrated second cracking catalyst flow 174a (512)
that may be provided to a secondary reactor 32. Such an embodiment
is illustrated in FIG. 8C, for example. A similar integration of a
transport zone 171 and a disengagement vessel 170 may likewise be
used in the embodiment of FIG. 11, as another example.
Further, as with the embodiment of FIGS. 9A and 9B, the outlets
75a, 74a may be configured such that the lighter/smaller particles
are concentrated in second riser reactor 71. For example, the
heavier/larger particles in internal vessel 73 may be returned to
regenerator 24, while the lighter/smaller particles in annular
region 78 may be fed to second riser reactor 71. In this manner,
the particles most suited for conversion of the feed to second
riser reactor 71 may be concentrated within the reactor.
As described for embodiments above, a second reactor is integrated
with a FCC riser reactor and separation system. This reactor is in
flow communication with other vessels, allowing selective catalytic
processing and integrated hydrocarbon product quenching, separation
and catalyst regeneration. Such an integrated reactor system offers
one or more of the above advantages and features of embodiments of
the processes disclosed herein may provide for an improved or
optimal process for the catalytic cracking of hydrocarbons for
light olefin production.
Embodiments herein may employ two types of catalyst particles, such
as Y-zeolite/FCC catalyst of smaller particle size and/or less
density and ZSM-5 particles larger in size and/or denser than the
former. A separator with selective recycle may be utilized to
preferentially segregate the Y-zeolite from ZSM-5 catalyst. Use of
such catalyst system allows entrainment of lighter and smaller
particles, thereby retaining ZSM-5 type particles within the
additional new reactor bed. The reactants undergo selective
catalytic cracking in presence of ZSM-5 type catalyst that is
preferred to maximize the yield of light olefins from C.sub.4 and
naphtha feed streams. The separator is a device which can
facilitate the separation of two types of catalysts due to the
difference in their particle size and/or density. Examples of
separators with selective recycle may be a cyclone separator, a
screen separator, mechanical sifters, a gravity chamber, a
centrifugal separator, an in-line or pneumatic classifier, or other
types of separators useful for efficiently separating particles
based on size and/or hydrodynamic properties. The separator is
connected to the top of the second reactor which is in flow
communication with second reactor as well as regenerator and first
reactor/stripper.
The reactor, in some embodiments, may be provided with baffles or
modular grid internals. This provides intimate contact of catalyst
with hydrocarbon feed molecules, helps in bubble breakage and
avoiding bubble growth due to coalescence, channeling or bypassing
of either catalyst or feed.
Conventionally, fresh catalyst make-up for maintaining the catalyst
activity is introduced to the regenerator bed using plant air. In
contrast, it is proposed to inject the desired high concentration
catalyst/additive directly into the second reactor bed using steam
or nitrogen as conveying media. This helps to produce incremental
increases in concentration and favorable selectivity.
The reactor configurations described herein provide enough
flexibility and operating window to adjust operating conditions
such as weight hourly space velocity (WHSV), catalyst and
hydrocarbon vapor residence time, reaction temperature,
catalyst/oil ratio, etc. As for example, in some embodiments, the
second reactor top/bed temperature is controlled by adjusting
catalyst flow from regenerator which indirectly controls the
catalyst/oil ratio. Whereas reactor bed level may be controlled by
manipulating the spent catalyst flow from reactor to regenerator,
which controls the WHSV and catalyst residence time.
While the disclosure includes a limited number of embodiments,
those skilled in the art, having benefit of this disclosure, will
appreciate that other embodiments may be devised which do not
depart from the scope of the present disclosure. Accordingly, the
scope should be limited only by the attached claims.
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